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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 033-73160
CALPINE CORPORATION
(A DELAWARE CORPORATION)
I.R.S. EMPLOYER IDENTIFICATION NO. 77-0212977
50 WEST SAN FERNANDO STREET
SAN JOSE, CALIFORNIA 95113
TELEPHONE: (408) 995-5115
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
CALPINE CORPORATION COMMON STOCK, $0.001 PAR VALUE REGISTERED ON THE NEW YORK
STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE.
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
Registrant as of February 23, 2000: $5.7 billion. Common stock outstanding as of
February 23, 2000: 63,215,367
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the Proxy Statement relating to
the 2000 Annual Meeting of Shareholders................. Part III (Items 10, 11 and 12)
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FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1999
TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business.................................................... 3
Item 2. Properties.................................................. 24
Item 3. Legal Proceedings........................................... 26
Item 4. Submission of Matters To A Vote of Security Holders......... 26
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 26
Item 6. Selected Financial Data..................................... 27
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 27
Item 7a. Quantitative and Qualitative Disclosure about Market Risk... 27
Item 8. Financial Statements and Supplementary Data................. 27
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 27
PART III
Item 10. Executive Officers, Directors and Key Employees............. 27
Item 11. Executive Compensation...................................... 27
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 27
Item 13. Certain Relationships and Related Transactions.............. 28
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 28
Signatures............................................................ 32
Index to Consolidated Financial Statements and Other Information...... F-1
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ITEM 1. BUSINESS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding the intent, belief or current
expectations of the Company and its management. Prospective investors are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties; actual results
could differ materially from those indicated by such forward-looking statements.
Among the important factors that could cause actual results to differ materially
from those indicated by such forward-looking statements are: (i) that the
information is of a preliminary nature and may be subject to further adjustment,
(ii) those risks and uncertainties identified under "Risk Factors" included in
Item 1. Business in this Annual Report on Form 10-K, (iii) the possible
unavailability of financing, (iv) risks related to the development, acquisition
and operation of power plants, (v) the impact of avoided cost pricing, energy
price fluctuations and gas price increases, (vi) the impact of curtailment,
(vii) the seasonal nature of the Company's business, (viii) start-up risks, (ix)
general operating risks, (x) the dependence on third parties, (xi) risks
associated with international investments, (xii) risks associated with the power
marketing business, (xiii) changes in government regulation, (xiv) the
availability of natural gas, (xv) the effects of competition, (xvi) the
dependence on senior management, (xvii) volatility in the Company's stock price,
(xviii) fluctuations in quarterly results and seasonality, and (xix) other risks
identified from time to time in the Company's reports and registration
statements filed with the Securities and Exchange Commission.
OVERVIEW
Calpine is a leading independent power company engaged in the development,
acquisition, ownership and operation of power generation facilities and the sale
of electricity predominantly in the United States. We have experienced
significant growth in all aspects of our business over the last five years.
Currently, we own interests in 44 power plants having an aggregate capacity of
4,273 megawatts. We also have ten gas-fired projects and two project expansions
under construction having an aggregate capacity of 5,935 megawatts and have
announced plans to develop twelve gas-fired power plants with a total capacity
of 7,990 megawatts. Upon completion of our projects under construction, we will
have interests in 54 power plants located in 17 states having an aggregate
capacity of 10,208 megawatts, of which we will have a net interest in 8,531
megawatts. Of this total generating capacity, 90% will be attributable to
gas-fired facilities and 10% will be attributable to geothermal facilities.
As a result of our expansion program, our revenues, cash flow, earnings and
assets have grown significantly over the last five years, as shown in the table
below.
COMPOUND ANNUAL
1994 1999 GROWTH RATE
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(DOLLARS IN MILLIONS)
Total Revenue......................... $ 94.8 $ 847.7 55%
EBITDA................................ 53.7 392.2 49%
Net Income............................ 6.0 95.1 74%
Total Assets.......................... 421.4 3,991.6 57%
Since our inception in 1984, we have developed substantial expertise in all
aspects of the development, acquisition and operation of power generation
facilities. We believe that the vertical integration of our extensive
engineering, construction management, operations, fuel management and financing
capabilities provides us with a competitive advantage to successfully implement
our acquisition and development program and has contributed to our significant
growth over the past five years.
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THE MARKET
The power industry represents the third largest industry in the United
States, with an estimated end-user market of over $225 billion of electricity
sales in 1999 produced by an aggregate base of power generation facilities with
a capacity of approximately 785,000 megawatts. In response to increasing
customer demand for access to low-cost electricity and enhanced services, new
regulatory initiatives have been and are continuing to be adopted at both the
state and federal level to increase competition in the domestic power generation
industry. The power generation industry historically has been largely
characterized by electric utility monopolies producing electricity from old,
inefficient, high-cost generating facilities selling to a captive customer base.
Industry trends and regulatory initiatives have transformed the existing market
into a more competitive market where end-users purchase electricity from a
variety of suppliers, including non-utility generators, power marketers, public
utilities and others.
There is a significant need for additional power generating capacity
throughout the United States, both to satisfy increasing demand, as well as to
replace old and inefficient generating facilities. Due to environmental and
economic considerations, we believe this new capacity will be provided
predominantly by gas-fired facilities. We believe that these market trends will
create substantial opportunities for efficient, low-cost power producers that
can produce and sell energy to customers at competitive rates.
In addition, as a result of a variety of factors, including deregulation of
the power generation market, utilities, independent power producers and
industrial companies are disposing of power generation facilities. To date,
numerous utilities have sold or announced their intentions to sell their power
generation facilities and have focused their resources on the transmission and
distribution business segments. Many independent producers operating a limited
number of power plants are also seeking to dispose of their plants in response
to competitive pressures, and industrial companies are selling their power
plants to redeploy capital in their core businesses.
STRATEGY
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power market, primarily through our active
development and acquisition programs. In pursuing our growth strategy, we
utilize our management and technical knowledge to implement a fully integrated
approach to the acquisition, development and operation of power generation
facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource production and
acquisition, operations and power marketing, which we believe provides us with a
competitive advantage. The key elements of our strategy are as follows:
- Development of new and expansion of existing power plants. We are
actively pursuing the development of new and expansion of our existing
highly efficient, low-cost, gas-fired power plants to replace old and
inefficient generating facilities and meet the demand for new generation.
- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent criteria, provide significant
potential for revenue, cash flow and earnings growth and provide the
opportunity to enhance the operating efficiencies of the plants.
- Enhancement of existing power plants. We continually seek to maximize the
power generation and revenue potential of our operating assets and
minimize our operating and maintenance expenses and fuel costs.
RECENT DEVELOPMENTS
Project Development and Construction. In May 1999, we completed a 35
megawatt expansion of our Clear Lake Power Plant to 412 megawatts, and the 169
megawatt Dighton Power Plant commenced commercial operations in August 1999.
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We currently have twelve projects under construction representing 5,935
additional megawatts. Of these new projects, we are currently expanding our
Pasadena facility by 545 megawatts to 785 megawatts and the Morris facility by
50 megawatts to 167 megawatts. We have ten new power plants under construction,
including the Baytown Power Plant in Texas; Tiverton Power Plant in Rhode
Island; the Rumford Power Plant in Maine; the Westbrook Energy Center in Maine;
the Sutter Power Plant in California; the South Point Power Plant in Arizona;
the Lost Pines 1 Power Plant in Texas; the Los Medanos Energy Center in
California; the Magic Valley Generation Station in Texas; and the Aries Power
Plant in Missouri. We have also announced plans to develop twelve additional
power generation facilities, totaling 7,990 megawatts, in California,
Mississippi, Texas, Arizona, Pennsylvania, Oregon, Alabama, Connecticut and
Florida.
In August 1999, we announced the purchase of 18 F-class combustion turbines
from Siemens Westinghouse Power Corporation that will be capable of producing
4,900 megawatts of electricity in a combined-cycle configuration. Beginning in
2002, Siemens will deliver six turbines per year through 2004. Combined with our
existing turbine orders we have 69 turbines under contract, option, letter of
intent or other commitment capable of producing approximately 18,800 megawatts
in a combined cycle configuration.
In November 1999, we executed an agreement with Credit Suisse First Boston,
New York branch and The Bank of Nova Scotia, as lead arrangers, for a $1.0
billion non-recourse revolving construction loan facility. We will use the
credit facility to finance the construction of our diversified portfolio of
gas-fired power plants currently under development in a combined cycle
configuration.
Acquisitions. In March 1999, we completed the acquisition of Unocal
Corporation's Geysers geothermal steam fields in northern California for
approximately $102.2 million. The steam fields fuel our 12 Sonoma County power
plants, totaling 544 megawatts, purchased from Pacific Gas and Electric Company
("PG&E") in May 1999.
In May 1999, we completed the acquisitions from PG&E of 14 geothermal power
plants at The Geysers in northern California, with a combined capacity of
approximately 700 megawatts, for $212.8 million. With these acquisitions plus
the acquisition of the Calistoga Power Plant in October 1999 and our increased
stake in the Aidlin Power Plant in August 1999, we now own interests in and
operate 19 geothermal power plants that generate more than 888 megawatts of
electricity, and we are the nation's largest geothermal and green power
producer. The combination of our existing geothermal steam and power plant
assets, the acquisition of the Sonoma steam fields from Unocal, and the 14 power
plants from PG&E together with the Calistoga Power Plant and our increased stake
in the Aidlin Power Plant allows us to fully integrate the steam and power plant
operations at The Geysers into one efficient, unified system to maximize the
renewable natural resource, lower overall production costs and extend the life
of The Geysers.
In August 1999, we completed the acquisition of an additional 50% of the
Aidlin Power Plant from Edison Mission Energy (5%) and General Electric Capital
Corporation (45%) for a total purchase price of $7.2 million. We now own 55% of
the 20 megawatt Aidlin Power Plant.
In October 1999, we completed the acquisition of Sheridan Energy, Inc., a
natural gas exploration and production company, through a $38.8 million cash
tender offer. We purchased all of the outstanding shares of Sheridan Energy's
common stock for $5.50 per share. In addition, we redeemed $11.9 million of
outstanding preferred stock of Sheridan Energy. Sheridan Energy's oil and gas
properties, including approximately 148 billion cubic feet equivalent of proven
reserves as of July 1, 1999 and certain leasehold acreage, are located in
northern California and the Gulf Coast region, where we are developing low-cost
natural gas supplies and proprietary pipeline systems to support our
strategically-located natural gas-fired power plants. We subsequently renamed
Sheridan Energy as Calpine Natural Gas Company.
In October 1999, we completed the acquisition of the Calistoga Power Plant
from FPL Energy and Caithness Corporation for approximately $77.9 million.
Located in The Geysers region of northern California, Calistoga is a 67 megawatt
facility which provides electricity to PG&E under a long-term contract.
In December 1999, we acquired 80% of the common stock of Cogeneration
Corporation of America, Inc. ("CGCA") for $25.00 per share or approximately
$137.3 million. NRG Energy, Inc., a wholly owned subsidiary of Northern States
Power, owns the remaining 20%. CGCA owns interests in six natural gas-fired
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power plants, totaling 579 megawatts. The plants are located in Pennsylvania,
New Jersey, Illinois and Oklahoma.
In December 1999, but effective as of November 1, 1999, we completed the
acquisition of Vintage Petroleum, Inc.'s interest in the Rio Vista Gas Unit and
related areas for approximately $71.5 million. As of the effective date of the
acquisition, Vintage owned approximately 90 billion cubic feet of proven natural
gas reserves and certain leasehold acreage located in the Sacramento Basin in
northern California. As a result of this acquisition and the Sheridan Energy
acquisition, we own a 99.5% working interest in the Rio Vista Gas Unit and
certain development acreage in northern California.
In January 2000, we acquired a 50% interest in the Aries Power Plant, a 600
megawatt natural gas-fired plant currently under construction near Pleasant
Hill, Missouri from a subsidiary of Aquila Energy Corporation. Construction
started in October 1999. Commercial operation of the first 330 megawatts is
scheduled to begin June 2001 with the balance of the plant starting in January
2002. The majority of the facility's output will be sold to Missouri Public
Service through May 2005. Thereafter, power will be sold into the Southwest
Power Pool.
In February 2000, we acquired 100% of the stock of Western Gas Resources
California ("Western") from Western Gas Resources, Inc. for $14.9 million.
Western's assets include the 130-mile Steelhead natural gas pipeline and the
remaining interest in the Sacramento River Gas System ("SRGS") natural gas
pipeline, now 100% owned by us.
Enhancement of Existing Power Plants. In July 1999, we announced a
renegotiation of our Gilroy power sales agreement with PG&E. The amendment
provides for the termination of the remaining 18 years of the long-term contract
in exchange for a fixed long-term payment schedule. The amended agreement was
approved by the California Public Utilities Commission in December 1999. We will
continue to sell the output from the Gilroy Power Plant through October 2002 to
PG&E and thereafter we will market the output in the California wholesale power
market.
Issuance of Securities. In October 1999, we completed a public offering of
8,280,000 shares of our common stock at $46.31 per share and 5,520,000 5 3/4%
HIGH TIDES issued by a subsidiary trust at $50.00 each, raising $636.7 million
of aggregate net proceeds.
In January 2000, we completed an offering under Rule 144A of the Securities
Act of 6,000,000 5 1/2% HIGH TIDES issued by a subsidiary trust at $50.00 each,
raising $292.4 million of aggregate net proceeds. In February 2000, we sold an
additional 1,200,000 5 1/2% HIGH TIDES pursuant to the exercise of the
underwriters' over-allotment option for net proceeds of approximately $58.6
million.
DESCRIPTION OF FACILITIES
We currently have interests in 44 power generation facilities with a
current aggregate capacity of approximately 4,273 megawatts, consisting of 25
gas-fired cogeneration plants with a total capacity of 3,385 megawatts and 19
geothermal power generation facilities with a total capacity of 888 megawatts.
We also have ten gas-fired projects and two project expansions currently under
construction with an aggregate capacity of 5,935 megawatts, and have announced
the development of twelve additional power plants with an aggregate capacity of
7,990 megawatts. Each of the power generation facilities currently in operation
produces electricity for sale to a utility or other third-party end user.
Thermal energy produced by the gas-fired cogeneration facilities is sold to
governmental and industrial users.
The gas-fired and geothermal power generation projects in which we have an
interest produce electricity and thermal energy that are typically sold pursuant
to long-term power sales agreements. Revenue from a power sales agreement
usually consists of two components: energy payments and capacity payments.
Energy payments are based on a power plant's net electrical output where payment
rates may be determined by a schedule of prices covering a fixed number of years
under the power sales agreement, after which payment rates are usually indexed
to the fuel costs of the contracting utility or to general inflation indices.
Capacity payments are based on a power plant's net electrical output and/or its
available capacity. Energy payments are
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made for each kilowatt hour of energy delivered, while capacity payments, under
certain circumstances, are made whether or not any electricity is delivered.
Upon completion of our projects under construction, we will provide
operating and maintenance services for 44 of the 54 power plants in which we
have an interest. Such services include the operation of power plants,
geothermal steam fields, wells and well pumps, gas fields, gathering systems and
gas pipelines. We also supervise maintenance, materials purchasing and inventory
control, manage cash flow, train staff and prepare operating and maintenance
manuals for each power generation facility that we operate. As a facility
develops an operating history, we analyze its operation and may modify or
upgrade equipment or adjust operating procedures or maintenance measures to
enhance the facility's reliability or profitability. These services are
performed under the terms of an operating and maintenance agreement pursuant to
which we are generally reimbursed for certain costs, paid an annual operating
fee and may also be paid an incentive fee based on the performance of the
facility. The fees payable to us are generally subordinated to any lease
payments or debt service obligations of non-recourse financing for the project.
In order to provide fuel for the gas-fired power generation facilities in
which we have an interest, natural gas reserves are acquired or natural gas is
purchased from third parties under supply agreements. We attempt to structure a
gas-fired power facility's fuel supply agreement so that gas costs have a direct
relationship to the fuel component of revenue energy payments. We currently hold
interests in geothermal leaseholds in The Geysers that produce steam that is
supplied to the power generation facilities owned by us for use in producing
electricity.
Certain power generation facilities in which we have an interest have been
financed primarily with non-recourse project financing that is structured to be
serviced out of the cash flows derived from the sale of electricity and thermal
energy produced by such facilities and provides that the obligations to pay
interest and principal on the loans are secured almost solely by the capital
stock or partnership interests, physical assets, contracts and/or cash flow
attributable to the entities that own the facilities. The lenders under
non-recourse project financing generally have no recourse for repayment against
us or any of our assets or the assets of any other entity other than foreclosure
on pledges of stock or partnership interests and the assets attributable to the
entities that own the facilities.
Substantially all of the power generation facilities in which we have an
interest are located on sites which are leased on a long-term basis. See
"Properties."
MEGAWATTS
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# OF PLANT CALPINE NET
PLANTS CAPACITY INTEREST
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In operation
Geothermal power plants.................. 19 888 879
Gas-fired power plants................... 25 3,385 2,476
Under construction
-- New facilities........................... 10 5,340 4,581
-- Expansion projects (two)................. -- 595 595
Announced development......................... 12 7,990 6,978
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66 18,198 15,509
== ====== ======
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Set forth below is certain information regarding our operating power
plants, plants under construction, and development projects.
POWER NAMEPLATE CALPINE CALPINE NET
GENERATION CAPACITY INTEREST INTEREST
POWER PLANT TECHNOLOGY LOCATION (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS)
----------- ---------- -------- -------------- ---------- -----------
OPERATING POWER PLANTS
GEOTHERMAL POWER PLANTS
Sonoma County (12 power Geothermal California 544.0 100.0% 544.0
plants)(2).....................
Lake County (2 power Geothermal California 150.0 100.0% 150.0
plants)(2).....................
Calistoga........................ Geothermal California 67.0 100.0% 67.0
Sonoma(2)........................ Geothermal California 60.0 100.0% 60.0
West Ford Flat................... Geothermal California 27.0 100.0% 27.0
Bear Canyon...................... Geothermal California 20.0 100.0% 20.0
Aidlin........................... Geothermal California 20.0 55.0% 11.0
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Subtotal....................... 888.0 879.0
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GAS-FIRED POWER PLANTS
Texas City....................... Gas-Fired Texas 450.0 100.0% 450.0
Clear Lake....................... Gas-Fired Texas 412.0 100.0% 412.0
Pasadena......................... Gas-Fired Texas 240.0 100.0% 240.0
Gordonsville..................... Gas-Fired Virginia 240.0 50.0% 120.0
Lockport......................... Gas-Fired New York 184.0 11.4% 20.9
Dighton(3)....................... Gas-Fired Massachusetts 169.0 50.0% 84.5
Bayonne.......................... Gas-Fired New Jersey 165.0 7.5% 12.4
Auburndale....................... Gas-Fired Florida 150.0 50.0% 75.0
Grays Ferry...................... Gas-Fired Pennsylvania 150.0 40.0% 60.0
Sumas(4)......................... Gas-Fired Washington 125.0 70.0% 87.5
Parlin........................... Gas-Fired New Jersey 122.0 80.0% 97.6
King City........................ Gas-Fired California 120.0 100.0% 120.0
Gilroy........................... Gas-Fired California 120.0 100.0% 120.0
Morris........................... Gas-Fired Illinois 117.0 80.0% 93.6
Pryor............................ Gas-Fired Oklahoma 110.0 80.0% 88.0
Kennedy International Airport.... Gas-Fired New York 107.0 50.0% 53.5
Pittsburg........................ Gas-Fired California 70.0 100.0% 70.0
Newark........................... Gas-Fired New Jersey 58.0 80.0% 46.4
Bethpage......................... Gas-Fired New York 57.0 100.0% 57.0
Greenleaf 1...................... Gas-Fired California 49.5 100.0% 49.5
Greenleaf 2...................... Gas-Fired California 49.5 100.0% 49.5
Stony Brook...................... Gas-Fired New York 40.0 50.0% 20.0
Agnews........................... Gas-Fired California 29.0 20.0% 5.8
Watsonville...................... Gas-Fired California 28.5 100.0% 28.5
Philadelphia..................... Gas-Fired Pennsylvania 22.0 66.4% 14.6
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Subtotal....................... 3,384.5 2,476.3
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PROJECTS UNDER CONSTRUCTION
Baytown.......................... Gas-Fired Texas 800.0 100.0% 800.0
Magic Valley..................... Gas-Fired Texas 730.0 100.0% 730.0
Aries............................ Gas-Fired Missouri 600.0 50.0% 300.0
Westbrook........................ Gas-Fired Maine 545.0 100.0% 545.0
Pasadena Expansion............... Gas-Fired Texas 545.0 100.0% 545.0
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POWER NAMEPLATE CALPINE CALPINE NET
GENERATION CAPACITY INTEREST INTEREST
POWER PLANT TECHNOLOGY LOCATION (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS)
----------- ---------- -------- -------------- ---------- -----------
South Point...................... Gas-Fired Arizona 545.0 100.0% 545.0
Sutter........................... Gas-Fired California 545.0 100.0% 545.0
Lost Pines 1..................... Gas-Fired Texas 545.0 50.0% 272.5
Los Medanos...................... Gas-Fired California 500.0 100.0% 500.0
Tiverton(5)...................... Gas-Fired Rhode Island 265.0 62.8% 166.4
Rumford(6)....................... Gas-Fired Maine 265.0 66.7% 176.8
Morris Expansion................. Gas-Fired Illinois 50.0 100.0% 50.0
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Subtotal....................... 5,935.0 5,175.7
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ANNOUNCED DEVELOPMENT
Blue Heron....................... Gas-Fired Florida 1,080.0 100.0% 1,080.0
Delta............................ Gas-Fired California 880.0 50.0% 440.0
Lone Oak......................... Gas-Fired Mississippi 800.0 100.0% 800.0
Decatur.......................... Gas-Fired Alabama 700.0 100.0% 700.0
Hillabee......................... Gas-Fired Alabama 700.0 100.0% 700.0
Metcalf.......................... Gas-Fired California 600.0 50.0% 300.0
Channel.......................... Gas-Fired Texas 560.0 100.0% 560.0
Ontelaunee....................... Gas-Fired Pennsylvania 545.0 100.0% 545.0
West Phoenix..................... Gas-Fired Arizona 545.0 50.0% 272.5
Osprey........................... Gas-Fired Florida 540.0 100.0% 540.0
Hermiston........................ Gas-Fired Oregon 540.0 100.0% 540.0
Towantic......................... Gas-Fired Connecticut 500.0 100.0% 500.0
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Subtotal....................... 7,990.0 6,977.5
======= =======
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(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.
(2) For these geothermal power plants, nameplate capacity refers to the
approximate capacity of the power plants. The capacity of these plants is
expected to gradually diminish as the production of the related steam fields
declines.
(3) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Dighton Power Plant" for a description of our interest
in the Dighton Power Plant. Based on our current estimates, our interest
represents our right to receive approximately 50% of project cash flow
beginning at the commencement of commercial operation.
(4) See "Operating Power Plants -- Sumas Power Plant" for a description of our
interest in the Sumas Power Plant. Based on our current estimates, the
payments to be received by us represent approximately 70% of distributable
cash.
(5) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Tiverton Power Plant" for a description of our
interest in the Tiverton Power Plant.
(6) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Rumford Power Plant" for a description of our interest
in the Rumford Power Plant.
OPERATING POWER PLANTS
Geothermal Power Plants
Sonoma County Power Plants. The Sonoma County power plants consist of 12
geothermal power plants and associated steam fields having combined capacity of
544 megawatts located at The Geysers in northern California. The power plants
were acquired from PG&E on May 7, 1999 and we market the output from these
plants into the California power market. Subsequent to their acquisition, the
Sonoma County power plants
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generated approximately 2,466,480 megawatt hours of electrical energy and
approximately $134.7 million of total revenues.
Lake County Power Plants. The Lake County power plants consist of two
geothermal power plants and associated steam fields having a combined capacity
of 150 megawatts located at The Geysers in northern California. We acquired
these power plants from PG&E on May 7, 1999, and we market the output from these
plants into the California power market. Subsequent to their acquisition, the
Lake County Power Plants generated approximately 703,327 megawatt hours of
electrical energy and approximately $30.1 million of total revenues.
Calistoga Power Plant. The Calistoga Power Plant consists of a 67 megawatt
geothermal power plant and associated steam fields located in northern
California. Electricity generated by the Calistoga Power Plant is sold to PG&E
under a power sales agreement terminating in 2014 which contains payment
provisions for capacity and energy. Subsequent to its acquisition in October
1999, the Calistoga Power Plant generated approximately 106,433 megawatt hours
of electrical energy and approximately $5.6 million of total revenue.
Sonoma Power Plant. The Sonoma Power Plant consists of a 60 megawatt
geothermal power plant and associated steam fields located in Sonoma County,
California. Electricity generated by the Sonoma Power Plant is sold to the
Sacramento Municipal Utility District ("SMUD") under a power sales agreement for
up to 50 megawatts of peak power production, terminating in 2001. In addition,
beginning on December 31, 1999, SMUD has the option to purchase up to an
additional 10 megawatts of peak power production through 2005. We market the
excess electricity into the California power market. During 1999, the Sonoma
Power Plant generated approximately 345,078 megawatt hours of electrical energy
and approximately $10.6 million in revenue.
West Ford Flat Power Plant. The West Ford Flat Power Plant consists of a 27
megawatt geothermal power plant and associated steam fields located in northern
California. Electricity generated by the West Ford Flat Power Plant is sold to
PG&E under a power sales agreement terminating in 2008 which contains payment
provisions for capacity and energy. During 1999, the West Ford Flat Power Plant
generated approximately 195,773 megawatt hours of electrical energy for sale to
PG&E and approximately $10.8 million of revenue.
Bear Canyon Power Plant. The Bear Canyon Power Plant consists of a 20
megawatt geothermal power plant and associated steam fields located in northern
California, two miles south of the West Ford Flat Power Plant. Electricity
generated by the Bear Canyon Power Plant is sold to PG&E under two 10 megawatt
power sales agreements terminating in 2008 which contain payment provisions for
capacity and energy. During 1999, the Bear Canyon Power Plant generated
approximately 143,080 megawatt hours of electrical energy and approximately $7.9
million of revenue.
Aidlin Power Plant. The Aidlin Power Plant consists of a 20 megawatt
geothermal power plant and associated steam fields located in northern
California. We hold an indirect 55% ownership interest in the Aidlin Power
Plant. Electricity generated by the Aidlin Power Plant is sold to PG&E under two
10 megawatt power sales agreements terminating in 2009 which contain payment
provisions for capacity and energy. During 1999, the Aidlin Power Plant
generated approximately 156,251 megawatt hours of electrical energy and revenue
of $13.3 million.
Gas-Fired Power Plants
Texas City Power Plant. The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. Electricity
generated by the Texas City Power Plant is sold under a long-term agreements to
Texas Utilities Electric Company ("TUEC") under a power sales agreement
terminating on September 30, 2002, and Union Carbide Corporation ("UCC") under a
steam and electricity services agreement which terminates on October 19, 2003.
Each agreement contains payment provisions for capacity and electric energy
payments. During 1999, the Texas City Power Plant generated approximately
2,843,494 megawatt hours of electric energy for sale to TUEC and UCC and
approximately $157.7 million of revenue.
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Clear Lake Power Plant. The Clear Lake Power Plant is a 412 megawatt
gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. Electricity
generated by the Clear Lake Power Plant is sold under three separate long-term
agreements to (1) Texas-New Mexico Power Company ("TNP") under a power sales
agreement terminating in 2004, (2) Houston Lighting and Power Company ("HL&P")
under a power sales agreement terminating in 2005, and (3) Hoechst Celanese
Chemical Group, Inc. ("HCCG") under a power sales agreement terminating in 2004.
Each power sales agreement contains payment provisions for capacity and energy
payments. Under a steam purchase and sale agreement expiring August 31, 2004,
the Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG.
During 1999, the Clear Lake Power Plant generated approximately 2,780,074
megawatt hours of electric energy for sale to TNP, HL&P and HCCG and
approximately $87.5 million of revenue.
Pasadena Power Plant. The Pasadena Power Plant is a 240 megawatt gas-fired
cogeneration facility located in Pasadena, Texas. Electricity generated by the
Pasadena Power Plant is sold under contract and into the open market. We entered
into an energy sales agreement with Phillips Petroleum Company ("Phillips")
terminating in 2018. Under this agreement, we provide 90 megawatts of
electricity and 200,000 lbs/hr of steam to Phillips' Houston Chemical Complex.
West Texas Utilities purchased 50 megawatts of capacity through the end of 1998.
In 1999, LG&E Energy Marketing purchased up to 150 megawatts of electricity
under a one-year agreement. TUEC is also under contract to purchase up to 150
megawatts of electricity under a two-year agreement beginning December 1, 1999.
The remaining available electricity output is sold into the competitive market
through our power marketing organization. During 1999, the Pasadena Power Plant
generated approximately 1,734,241 megawatt hours of electric energy with
approximately $65.9 million of revenue.
Gordonsville Power Plant. The Gordonsville Power Plant, of which we own
50%, is a 240 megawatt gas-fired cogeneration facility located near
Gordonsville, Virginia. Electricity generated by the Gordonsville Power Plant is
sold to the Virginia Electric and Power Company under two power sales agreements
terminating on June 1, 2024, each of which include payment provisions for
capacity and energy. The Gordonsville Power Plant sells steam to Rapidan Service
Authority under the terms of a steam purchase and sales agreement, which expires
June 1, 2004. During 1999, the Gordonsville Power Plant generated approximately
182,970 megawatt hours of electrical energy and approximately $39.3 million of
revenue.
Lockport Power Plant. The Lockport Power Plant is a 184 megawatt gas-fired,
combined-cycle cogeneration facility located in Lockport, New York. The facility
is owned and operated by Lockport Energy Associates, L.P. ("LEA"). We own an
indirect 11.36% limited partnership interest in LEA. Electricity and steam is
sold to General Motors Corporation ("GM") under an energy sales agreement
expiring in December 2007 for use at the GM Harrison plant, which is located on
a site adjacent to the Lockport Power Plant. Electricity is also sold to New
York State Electricity and Gas Company ("NYSEG") under a power purchase
agreement expiring October 2007. NYSEG is required to purchase all of the
electric power produced by the Lockport Power Plant not required by GM. For
1999, the Lockport Power Plant generated approximately 1,614,513 megawatt hours
of electricity and had $92.0 million in revenue.
Dighton Power Plant. In October 1997, we invested $16.0 million in the
development of a 169 megawatt gas-fired combined-cycle power plant to be located
in Dighton, Massachusetts. This investment, which is structured as subordinated
debt, will provide us with a preferred payment stream at a rate of 12.07% per
year for a period of twenty years from the commercial operation date. Commercial
operation commenced in August 1999. The Dighton Power Plant is operated by
Energy Management Inc.("EMI") and sells its output into the New England power
market and to wholesale and retail customers in the northeastern United States.
Since its start-up in 1999, the Dighton Power Plant generated approximately
367,671 megawatt hours of electrical energy and approximately $20.6 million of
total revenues.
Bayonne Power Plant. The Bayonne Power Plant is a 165 megawatt gas-fired
cogeneration facility located in Bayonne, New Jersey. The facility is primarily
owned by an affiliate of Cogen Technologies, Inc. We own an indirect 7.5%
partnership interest in the facility. Electricity generated by the Bayonne Power
Plant is sold under various power sales agreements to Jersey Central Power &
Light Company ("JCP&L") and Public Service Electric and Gas Company of New
Jersey. The Bayonne Power Plant also sells steam to two
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industrial entities. During 1999, the Bayonne Power Plant generated
approximately 1,430,000 megawatt hours of electrical energy and approximately
$109.8 million in revenue.
Auburndale Power Plant. The Auburndale Power Plant, of which we own 50%, is
a 150 megawatt gas-fired cogeneration facility located near the city of
Auburndale, Florida. Electricity generated by the Auburndale Power Plant is sold
under various power sales agreements to Florida Power Corporation ("FPC"), Enron
Power Marketing and Sonat Power Marketing. Auburndale sells 131 megawatts of
capacity and energy to FPC under three power sales agreements, each terminating
at the end of 2013. The Auburndale Power Plant sells steam under two steam
purchase and sale agreements. One agreement is with Cutrale Citrus Juices, USA,
an affiliate of Sucocitro Cutrale LTDA, expiring on July 1, 2014. The second
agreement is with Todhunter International, Inc., doing business as Florida
Distillers Company, expiring on July 1, 2009. During 1999, the Auburndale Power
Plant generated approximately 1,027,466 megawatt hours of electrical energy and
approximately $52.3 million in revenue.
Grays Ferry Power Plant. The Grays Ferry Power Plant is a 150 megawatt,
natural gas-fired cogeneration project located in Philadelphia, Pennsylvania. We
indirectly own 40% of this project. Electricity generated by the Grays Ferry
Power Plant is sold under two long-term power sales agreements to PECO Energy
Company, expiring in 2017. An affiliate of Trigen Energy Corporation purchases
the steam produced by the project pursuant to a 25-year contract expiring in
2022. Subsequent to our acquisition of CGCA in December 1999, the Grays Ferry
Power Plant generated approximately 46,125 megawatt hours of electrical energy
and approximately $3.7 million in revenue in 1999.
Sumas Power Plant. The Sumas Power Plant is a 125 megawatt gas-fired,
combined cycle cogeneration facility located in Sumas, Washington. We currently
hold an ownership interest in the Sumas Power Plant, which entitles us to
receive certain scheduled distributions during the next two years. Upon receipt
of the scheduled distributions, we will no longer have any ownership interest in
the Sumas Power Plant. Electrical energy generated by the Sumas Power Plant is
sold to Puget Sound Power & Light Company ("Puget") under the terms of a power
sales agreement terminating in 2013. Under the power sales agreement, Puget has
agreed to purchase an annual average of 123 megawatts of electrical energy. In
addition to the sale of electricity to Puget, pursuant to a long-term steam
supply and dry kiln lease agreement, the Sumas Power Plant produces and sells
approximately 23,000 lbs/hr of low pressure steam to an adjacent lumber-drying
facility owned by Sumas, which has been leased to and is operated by Socco, Inc.
During 1999, the Sumas Power Plant generated approximately 666,598 megawatt
hours of electrical energy and approximately $52.8 million of total revenue.
Parlin Power Plant. The Parlin Power Plant consists of a 122 megawatt
natural gas-fired cogeneration power plant located in Parlin, New Jersey.
Electricity generated by the Parlin Power Plant is sold pursuant to a long-term
contract expiring in 2011 to JCP&L, and steam produced is sold to E.I. Dupont de
Nemours and Company under a long-term agreement expiring in 2021. Subsequent to
our acquisition of this project in December 1999, the Parlin Power Plant
generated approximately 13,938 megawatt hours of electrical energy and
approximately $908,000 of total revenue in 1999.
King City Power Plant. The King City Power Plant is a 120 megawatt
gas-fired, combined-cycle cogeneration facility located in King City,
California. We operate the King City Power Plant under a long-term operating
lease for this facility with BAF Energy ("BAF"), terminating in 2018.
Electricity generated by the King City Power Plant is sold to PG&E under a power
sales agreement terminating in 2019. The power sales agreement contains payment
provisions for capacity and energy. In addition to the sale of electricity to
PG&E, the King City Power Plant produces and sells thermal energy to a thermal
host, Basic Vegetable Products, Inc., an affiliate of BAF, under a long-term
contract coterminous with the power sales agreement. During 1999, the King City
Power Plant generated approximately 645,836 megawatt hours of electrical energy
and approximately $44.2 million of total revenue.
Gilroy Power Plant. The Gilroy Power Plant is a 120 megawatt gas-fired
cogeneration facility located in Gilroy, California. Electricity generated by
the Gilroy Power Plant is sold to PG&E under a power sales agreement terminating
in 2018. In July 1999 we announced a renegotiation of our Gilroy power sales
agreement with PG&E. The amendment provides for the termination of the remaining
18 years of the long-
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term contract in exchange for a fixed long-term payment schedule. The amended
agreement was approved by the California Public Utilities Commission ("CPUC") in
December 1999. We will continue to sell the output from the Gilroy Power Plant
through October 2002 to PG&E and thereafter we will market the output in the
California wholesale power market. In addition, the Gilroy Power Plant produces
and sells thermal energy to a thermal host, Gilroy Foods, Inc., under a
long-term contract. During 1999, the Gilroy Power Plant generated approximately
950,848 megawatt hours of electrical energy for sale to PG&E and approximately
$67.2 million in revenue.
Morris Power Plant. The Morris Power Plant consists of a 117 megawatt
natural gas-fired cogeneration facility located in Morris, Illinois. We
indirectly own 80% of this project. Electricity and steam produced by the
facility is sold to Equistar Chemicals, L.P. pursuant to a long-term contract
expiring in 2023. Any surplus electricity is marketed to the Illinois power
market. Subsequent to our acquisition of this project in December 1999, the
Morris Power Plant generated approximately 13,809 megawatt hours of electrical
energy and approximately $1.3 million of total revenue in 1999. We are currently
expanding this facility by 50 megawatts.
Pryor Power Plant. The Pryor Power Plant is a 110 megawatt natural
gas-fired cogeneration power plant located in Pryor, Oklahoma. We indirectly own
80% of this project. The Pryor Power Plant sells 100-megawatts of capacity and
varying amounts of electrical energy to Oklahoma Gas and Electric Company under
a contract expiring at the end of 2007. Steam produced from the Pryor facility
is sold to a number of industrial users under contracts with various termination
dates ranging from 2000 to 2007. Surplus electricity is also sold to the Public
Service Company of Oklahoma at its avoided cost. Subsequent to our acquisition
of this project in December 1999, the Pryor Power Plant generated approximately
15,541 megawatt hours of electrical energy and approximately $791,000 of total
revenue in 1999.
Kennedy International Airport Power Plant. The Kennedy International
Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at
John F. Kennedy International Airport in Queens, New York. The facility is owned
and operated by KIAC Partners and leased from The Port Authority of New York and
New Jersey. We own an indirect 50% ownership interest in KIAC. Electricity and
thermal energy generated by the Kennedy International Airport Power Plant is
sold to the Port Authority, and incremental electric power is sold to
Consolidated Edison Company of New York, the New York Power Authority and other
utility customers. Electric power and thermal energy in the form of chilled and
hot water generated by the Kennedy International Airport Power Plant is sold to
the Port Authority under an energy purchase agreement that expires November
2015. For 1999, the Kennedy International Airport Power Plant generated
approximately 570,024 megawatt hours of electrical energy, 253,591 mmbtu of
chilled water and 204,009 mmbtu of hot water for sale to the Port Authority, and
generated approximately $59.3 million in revenue.
Pittsburg Power Plant. The Pittsburg Power Plant is a 70 megawatt gas-fired
cogeneration facility, located at The Dow Chemical Company's ("Dow") Pittsburg,
California chemical facility. We sell up to 18 megawatts of electricity to Dow
under a power sales agreement expiring in 2008. Surplus energy is sold to PG&E
under an existing power sales agreement. In addition, we sell approximately
200,000 lbs/hr of steam to Dow under an energy sales agreement expiring in 2003
and to USS-POSCO Industries' nearby steel mill under a process steam contract
expiring in 2001. During 1999, the Pittsburg Power Plant generated approximately
412,148 megawatt hours of electrical energy to Dow and PG&E and approximately
$22.1 million in revenue.
Newark Power Plant. The Newark Power Plant consists of a 58 megawatt
natural gas-fired cogeneration power plant located in Newark, New Jersey. We
indirectly own 80% of this project. Electricity produced by the facility is sold
pursuant to a long-term contract expiring in 2015 to JCP&L. Steam produced is
sold to Newark Boxboard, Inc. under a long-term contract expiring in 2015.
Subsequent to our acquisition of this project in December 1999, the Newark Power
Plant generated approximately 17,156 megawatt hours of electrical energy and
approximately $778,000 in revenue in 1999.
Bethpage Power Plant. The Bethpage Power Plant is a 57 megawatt gas-fired,
combined cycle cogeneration facility located adjacent to a Northrup Grumman
Corporation ("Grumman") facility in Bethpage, New York. Electricity and steam
generated by the Bethpage Power Plant are sold to Grumman
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under an energy purchase agreement expiring August 2004. Electric power not sold
to Grumman is sold to Long Island Power Authority ("LIPA") under a generation
agreement also expiring August 2004. Grumman is also obligated to purchase a
minimum of 158,000 klbs of steam per year from the Bethpage Power Plant. For
1999, the Bethpage Power Plant generated approximately 468,268 megawatt hours of
electrical energy for sale to Grumman and LIPA and approximately $32.6 million
in revenue.
Greenleaf 1 Power Plant. The Greenleaf 1 Power Plant is a 49.5 megawatt
gas-fired cogeneration facility located near Yuba City, California. We operate
this facility under an operating lease with Union Bank of California,
terminating in 2014 (the "Greenleaf Lease"). Electricity generated by the
Greenleaf 1 Power Plant is sold to PG&E under a power sales agreement
terminating in 2019 which contains payment provisions for capacity and energy.
In addition, the Greenleaf 1 Power Plant sells thermal energy, in the form of
hot exhaust to dry wood waste, to a thermal host which is owned and operated by
us. For 1999, the Greenleaf 1 Power Plant generated approximately 389,628
megawatt hours of electrical energy for sale to PG&E and approximately $20.7
million in revenue.
Greenleaf 2 Power Plant. The Greenleaf 2 Power Plant is a 49.5 megawatt
gas-fired cogeneration facility located near Yuba City, California. This
facility is also operated by us under the Greenleaf Lease. Electricity generated
by the Greenleaf 2 Power Plant is sold to PG&E under a power sales agreement
terminating in 2019 which includes payment provisions for capacity and energy.
In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant
sells thermal energy to Sunsweet Growers, Inc. pursuant to a 30-year contract.
For 1999, the Greenleaf 2 Power Plant generated approximately 345,902 megawatt
hours of electrical energy for sale to PG&E and approximately $20.0 million in
revenue.
Stony Brook Power Plant. The Stony Brook Power Plant is a 40 megawatt
gas-fired cogeneration facility located on the campus of the State University of
New York at Stony Brook, New York ("SUNY"). The facility is owned by Nissequogue
Cogen Partners ("NCP"). We own an indirect 50% ownership interest in NCP. Steam
and electric power is sold to SUNY under an energy supply agreement expiring in
2023. Under the energy supply agreement, SUNY is required to purchase, and the
Stony Brook Power Plant is required to provide, all of SUNY's electric power and
steam requirements up to 36.125 megawatts of electricity and 280,000 lbs/hr of
process steam. The remaining electricity is sold to LIPA under a long-term
agreement. LIPA is obligated to purchase electric power generated by the
facility not required by SUNY. SUNY is required to purchase a minimum of 402,000
klbs per year of steam. For 1999, the Stony Brook Power Plant generated
approximately 323,366 megawatt hours of electrical energy and 1,226,000 klbs of
steam for sale to SUNY and LIPA and approximately $30.8 million in revenue.
Agnews Power Plant. The Agnews Power Plant is a 29 megawatt gas-fired,
combined-cycle cogeneration facility located on the East Campus of the
state-owned Agnews Developmental Center in San Jose, California. We hold a 20%
ownership interest in GATX Calpine-Agnews, Inc., which is the sole stockholder
of O.L.S. Energy-Agnews, Inc. ("O.L.S. Energy-Agnews"). O.L.S. Energy-Agnews
leases the Agnews Power Plant under a sale leaseback arrangement. Electricity
generated by the Agnews Power Plant is sold to PG&E under a power sales
agreement terminating in 2021 which contains payment provisions for capacity and
energy. In addition, the Agnews Power Plant produces and sells electricity and
approximately 7,000 lbs/hr of steam to the Agnews Developmental Center pursuant
to a 30-year energy service agreement. During 1999, the Agnews Power Plant
generated approximately 228,781 megawatt hours of electrical energy and total
revenue of $23.0 million.
Watsonville Power Plant. The Watsonville Power Plant is a 28.5 megawatt
gas-fired, combined cycle cogeneration facility located in Watsonville,
California. We operate the Watsonville Power Plant under an operating lease with
the Ford Motor Credit Company, terminating in 2009. Electricity generated by the
Watsonville Power Plant is sold to PG&E under a power sales agreement
terminating in 2009 which contains payment provisions for capacity and energy.
During 1999, the Watsonville Power Plant produced and sold steam to Farmers
Processing, a food processor. In addition, the Watsonville Power Plant sold
process water produced from its water distillation facility to Farmer's Cold
Storage, Farmer's Processing and Cascade Properties. For 1999, the Watsonville
Power Plant generated approximately 193,584 megawatt hours of electrical energy
for sale to PG&E and approximately $11.5 million in revenue.
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Philadelphia Water Project. The Philadelphia Water Project is a 22 megawatt
gas-fired facility consisting of two standby peak shaving facilities located at
the Philadelphia Water Department's Northeast and Southwest wastewater treatment
plants. We indirectly own 66.4% of this project. The project sells capacity and
energy on demand to the Philadelphia Municipal Authority pursuant to two
long-term contracts expiring in 2013. Subsequent to our acquisition of this
project in December 1999, the Philadelphia Water Project generated approximately
$134,000 in revenue in 1999.
PROJECT DEVELOPMENT AND ACQUISITIONS
We are actively engaged in the development and acquisition of power
generation projects. We have historically focused principally on the development
and acquisition of interests in gas-fired and geothermal power projects,
although we also consider projects that utilize other power generation
technologies. We have significant expertise in a variety of power generation
technologies and have substantial capabilities in each aspect of the development
and acquisition process, including design, engineering, procurement,
construction management, fuel and resource acquisition and management, financing
and operations.
ACQUISITIONS
We will consider the acquisition of an interest in operating projects as
well as projects under development where we would assume responsibility for
completing the development of the project. In the acquisition of power
generation facilities, we generally seek to acquire an ownership interest in
facilities that offer us attractive opportunities for revenue and earnings
growth, and that permit us to assume sole responsibility for the operation and
maintenance of the facility. In evaluating and selecting a project for
acquisition, we consider a variety of factors, including the type of power
generation technology utilized, the location of the project, the terms of any
existing power or thermal energy sales agreements, gas supply and transportation
agreements and wheeling agreements, the quantity and quality of any geothermal
or other natural resource involved, and the actual condition of the physical
plant. In addition, we assess the past performance of an operating project and
prepare financial projections to determine the profitability of the project. We
generally seek to obtain a significant equity interest in a project and to
obtain the operation and maintenance contract for that project.
PROJECT DEVELOPMENT
The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, designing and
engineering the project, obtaining power sales agreements, acquiring necessary
land rights, permits and fuel resources, obtaining financing and managing
construction. We intend to focus primarily on development opportunities where we
are able to capitalize on our expertise in implementing an innovative and fully
integrated approach to project development in which we control the entire
development process. Utilizing this approach, we believe that we are able to
enhance the value of our projects throughout each stage of development in an
effort to maximize our return on investment.
We are pursuing the development of highly efficient, low-cost power plants
that seek to take advantage of inefficiencies in the electricity market. We
intend to sell all or a portion of the power generated by such plants into the
competitive market through a portfolio of short-, medium-and long-term power
sales agreements. We expect that these projects will represent a prototype for
our future plant developments.
Projects Under Construction
Baytown Power Plant. In October 1999, we announced plans to build, own and
operate a 800 megawatt gas-fired cogeneration power plant at Bayer Corporation's
chemical facility in Baytown, Texas. The Baytown Power Plant will supply Bayer
with all of its electric and steam requirements for 20 years and market excess
electricity into the Texas wholesale power market. Construction commenced in
early 2000 and commercial operation is expected to begin in late 2001.
Magic Valley Generating Station. In May 1998, we announced that we had
signed a 20-year power sales agreement to provide electricity to the Magic
Valley Electric Cooperative, Inc. of Mercedes, Texas beginning
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in 2001. The power will be supplied by our Magic Valley Generating Station, a
730 megawatt natural gas-fired power plant under development in Edinburg, Texas.
Magic Valley Electric Cooperative Inc., a 51,000 member non-profit electric
cooperative, initially will purchase from 250 to 400 megawatts of capacity, with
an option to purchase additional capacity. We are marketing additional capacity
to other wholesale customers, initially targeting south Texas. Construction
commenced in April 1999 with commercial operation scheduled to begin in early
2001.
Aries Power Plant. In January 2000, we acquired a 50% interest in the Aries
Power Plant, a 600 megawatt natural gas-fired plant currently under construction
near Pleasant Hill, Missouri, from a subsidiary of Aquila Energy Corporation.
Construction started in October 1999. Commercial operation of the first 330
megawatts is scheduled to begin June 2001 with the balance of the plant starting
in January 2002. The majority of the facility's output will be sold to Missouri
Public Service through May 2005. Thereafter, power will be sold into the
Southwest Power Pool.
Westbrook Energy Center. In February 1999, we acquired from Genesis Power
Corporation, a New England based power developer, the development rights to a
545 megawatt gas-fired combined-cycle power plant to be located in Westbrook,
Maine. Construction commenced in February 1999 and commercial operation is
scheduled for early 2001. It is anticipated that the output generated by the
Westbrook Energy Center will be sold into the New England power market and to
wholesale and retail customers in the northeastern United States.
Pasadena Expansion. We are currently expanding the Pasadena Power Plant by
an additional 545 megawatts. Construction began in November 1998 and commercial
operation is expected to begin in June 2000. The electricity output from this
expansion will be sold into the competitive market through our power sales
activities.
South Point Power Plant. In May 1998, we announced that we had entered into
a long-term lease agreement with the Fort Mojave Indian Tribe to develop a 545
megawatt gas-fired power plant on the tribe's reservation in Mojave County,
Arizona. The electricity generated will be sold to the Arizona, Nevada and
California power markets. Construction commenced in August 1999 and we
anticipate that the South Point Power Plant will begin operation in mid 2001.
Sutter Power Plant. In February 1997, we announced plans to develop a 545
megawatt gas-fired combined cycle project in Sutter County, in northern
California. The Sutter Power Plant would be northern California's first newly
constructed power plant since deregulation of the California power market in
1998. Construction commenced in August 1999 and the Sutter Power Plant is
expected to provide electricity to the deregulated California power market
commencing mid 2001
Lost Pines 1 Power Plant. In September 1999, we entered into definitive
agreements with Austin, Texas-based GenTex Power Corporation, the power
generation affiliate of the Lower Colorado River Authority, to build a 545
megawatt gas-fired facility in Bastrop County, Texas. Construction of this
facility began in October 1999 and commercial operation is expected to begin in
mid 2001. Upon commercial operation, GenTex will take half of the electrical
output for sale to its customers and we will market the remaining energy to the
Texas power market.
Los Medanos Energy Center. In September 1999, we finalized an agreement
with Enron North America for the development rights of a 500 megawatt gas-fired
plant in Pittsburg, California. Construction commenced in September 1999 and
commercial operation is expected to begin in mid 2001. The facility will provide
electricity and industrial steam totaling approximately 65 megawatts to
USS-POSCO Industries under a long-term agreement. The balance of the plant's
output will be sold into the California power market.
Tiverton Power Plant. In September 1998, we invested $40.0 million of
equity in the development of a 265 megawatt gas-fired power plant to be located
in Tiverton, Rhode Island. The Tiverton Power Plant is being developed by EMI.
For our investment in the Tiverton Power Plant, we will earn 62.8% of the
Tiverton Power Plant project cash flow until a specified pre-tax return is
reached, whereupon our company and EMI will equally share projected cash flows
through the remaining life of the project. Construction commenced in late 1998
and commercial operation is currently scheduled for May 2000. Upon completion,
the Tiverton
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Power Plant will be operated by EMI and will sell its output in the New England
power market and to wholesale and retail customers in the northeastern United
States.
Rumford Power Plant. In November 1998, we invested $40.0 million of equity
in the development of a 265 megawatt gas-fired power plant to be located in
Rumford, Maine. The Rumford Power Plant is being developed by EMI. For our
investment in the Rumford Power Plant, we will earn 66 2/3% of the Rumford Power
Plant project cash flow until a 10.5% pre-tax return is reached, whereupon we
will receive 50% of projected cash flows through the remaining life of the
project. Construction commenced in late 1998 and commercial operation is
currently scheduled for July 2000. Upon completion, the Rumford Power Plant will
be operated by EMI and will sell its output in the New England power market and
to wholesale and retail customers in the northeastern United States.
Morris Expansion. We are currently expanding the Morris Power Plant by
approximately 50 megawatts with the addition of a steam turbine. Construction
began in January 2000 with commercial operation scheduled for mid 2000.
Announced Development Projects
Blue Heron Energy Center. In January 2000 we announced plants to build, own
and operate a 1,080 megawatt gas-fired cogeneration power plant in Indian River
County, Florida. We anticipate that construction will commence in 2001 and that
commercial operation of the facility will commence in mid 2003.
Delta Energy Center. In February 1999, we, together with Bechtel
Enterprises, announced plans to develop a 880 megawatt gas-fired cogeneration
project in Pittsburg, California. The Delta Energy Center will provide steam and
electricity to the nearby Dow Chemical Company facility and market the excess
electricity into the California power market. We anticipate that construction
will commence in early 2000 and that operation of the facility will commence in
2002. We are currently pursuing regulatory agency permits for this project. In
February 2000, we announced that the California Energy Commission ("CEC") has
approved Delta Energy Center's Application for Certification.
Lone Oak Energy Center. In February 2000, we announced plans to build, own
and operate the Lone Oak Energy Center, a 800 megawatt gas-fired cogeneration
power plant in Lowndes County, Mississippi. We anticipate that construction will
commence in early 2001 and that commercial operation of the facility will
commence in early 2003.
Decatur Energy Center. In February 2000, we announced plans to build, own
and operate a 700 megawatt gas-fired cogeneration power plant at Solutia Inc.'s
Decatur, Alabama chemical facility. Under a 20 year agreement, Solutia will
lease a portion of the facility to meet its electricity needs and purchase its
steam requirements from us. Excess power from the facility will be sold into the
southeastern wholesale power market under a variety of short, mid and long term
contracts. We will also build a new intrastate natural gas pipeline to fuel the
new plant. Construction is estimated to commence in mid 2000 and commercial
operation in mid 2002.
Hillabee Energy Center. In February 2000, we announced plans to build, own
and operate the Hillabee Energy Center, a 700 megawatt gas-fired cogeneration
power plant in Tallapoosa County, Alabama. We anticipate that construction will
commence in early 2001 and that commercial operation of the facility will
commence in early 2003.
Metcalf Energy Center. In February 1999, we, together with Bechtel
Enterprises, announced plans to develop, own and operate a 600 megawatt
gas-fired cogeneration project in San Jose, California. We expect the CEC
review, licensing and public hearing process will be completed in late 2000 or
early 2001. We anticipate that construction will commence following this
approval and that commercial operation of the facility will commence in late
2002 or early 2003. Electricity generated by the Metcalf Energy Center will be
sold into the California power market.
Channel Energy Center. In October 1999, we announced that we had executed a
letter of intent which gives us the exclusive right to negotiate with
LYONDELL-CITGO Refining LP to build, own and operate a
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560 megawatt gas-fired cogeneration power plant at the LYONDELL-CITGO refinery
in Houston, Texas. The Channel Energy Center will supply all of the electricity
and steam requirements for 20 years to the refinery. Permitting for the facility
is currently underway, with construction projected to commence in early 2000 and
commercial operation in 2001.
Ontelaunee Energy Center. In June 1999, we announced that we had acquired
the rights to develop a 545 megawatt gas-fired power plant in Ontelaunee
Township in eastern Pennsylvania. Permitting for the proposed facility is
underway and construction is scheduled to begin in early 2000. Commercial
operation is estimated for late 2002. Output from the plant will be sold into
the Pennsylvania/New Jersey/Maryland (PJM) power pool and pursuant to bilateral
contracts.
West Phoenix Power Plant. In April 1999, we announced an agreement with
Pinnacle West Capital Corporation to develop, own and operate a 545 megawatt
gas-fired facility at Arizona Public Services' West Phoenix Power Station in
Phoenix, Arizona. Timing of development activities is still under discussion
with our partner. Electricity from the facility will be sold into the Arizona
power market.
Osprey Energy Center. In January 2000, we announced plans to build, own and
operate the Osprey Energy Center, a 540 megawatt gas-fired cogeneration power
plant near the city of Auburndale, Florida. The facility will be built adjacent
to our existing power facility, the Auburndale Power Plant. We anticipate that
construction will commence in 2001 and that commercial operation of the facility
will commence in early 2003.
Hermiston Power Plant. In January 2000, we acquired the development rights
for the Hermiston Power Project, a 540 megawatt gas-fired cogeneration power
facility located near Hermiston, Oregon. We anticipate that construction will
commence in the summer of 2000 and that commercial operation of the facility
will commence in 2002.
Towantic Energy Center. In November 1999, we completed the acquisition of
development rights to build, own and operate the Towantic Energy Center. The
Towantic Energy Center is a 500 megawatt gas-fired cogeneration plant located in
Oxford, Connecticut. This power plant will market its electricity via bilateral
contracts into the New England region. Construction is estimated to commence in
late 2000 and commercial operation in 2002. In February 2000, a townwide
referendum in the Town of Oxford, Connecticut approved the sale of the
town-owned land for the Towantic Energy Center.
OIL AND GAS PROPERTIES
Montis Niger. In January 1997, we purchased Montis Niger, Inc., a gas
production and pipeline company operating primarily in the Sacramento Basin in
northern California, which we subsequently renamed Calpine Gas Company. As of
December 31, 1999, Calpine Gas Company owned proven natural gas reserves,
leasehold acreage and operated an 80-mile pipeline delivering gas to the
Greenleaf 1 and 2 Power Plants. We currently supply approximately 79% of the
fuel requirements for the Greenleaf 1 and 2 Power Plants.
Calpine Natural Gas Company. In October 1999, we purchased Sheridan Energy,
Inc., a natural gas exploration and production company operating in northern
California and the Gulf Coast region, which we subsequently renamed Calpine
Natural Gas Company ("CNGC"). CNGC's oil and gas properties are primarily
natural gas and are located in strategic markets where we are developing
low-cost natural gas supplies and proprietary pipeline systems in support of its
natural gas-fired power plants.
Vintage. In December 1999, we completed the acquisition of Vintage
Petroleum, Inc.'s interest in the Rio Vista Gas Unit and related areas,
representing primarily natural gas reserves located in the Sacramento Basin in
northern California. As a result of this acquisition and the Sheridan Energy
acquisition, we own a 99.5% working interest in the Rio Vista Gas Unit and
certain development acreage in northern California.
Western. In February 2000, we acquired 100% of the stock of Western from
Western Gas Resources, Inc. Western's assets include the 130-mile Steelhead
natural gas pipeline and the remaining interest in the SRGS natural gas
pipeline, now 100% owned by us.
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GOVERNMENT REGULATION
We are subject to complex and stringent energy, environmental and other
governmental laws and regulations at the federal, state and local levels in
connection with the development, ownership and operation of its energy
generation facilities. Federal laws and regulations govern transactions by
electrical and gas utility companies, the types of fuel which may be utilized by
an electric generating plant, the type of energy which may be produced by such a
plant and the ownership of a plant. State utility regulatory commissions must
approve the rates and, in some instances, other terms and conditions under which
public utilities purchase electric power from independent producers and sell
retail electric power. Under certain circumstances where specific exemptions are
otherwise unavailable, state utility regulatory commissions may have broad
jurisdiction over non-utility electric power plants. Energy producing projects
also are subject to federal, state and local laws and administrative regulations
which govern the emissions and other substances produced, discharged or disposed
of by a plant and the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have both state and local
enforcement and implementation provisions. These environmental laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before the commencement of construction or operation of an
energy-producing facility and that the facility then operate in compliance with
such permits and approvals.
FEDERAL ENERGY REGULATION
PURPA
The enactment of the Public Utility Regulatory Policies Act of 1978, as
amended ("PURPA") and the adoption of regulations thereunder by the Federal
Energy Regulatory Commission ("FERC") provided incentives for the development of
cogeneration facilities and small power production facilities (those utilizing
renewable fuels and having a capacity of less than 80 megawatts).
A domestic electricity generating project must be a qualifying facility
("QF") under FERC regulations in order to take advantage of certain rate and
regulatory incentives provided by PURPA. PURPA exempts owners of QFs from the
Public Utility Holding Company Act of 1935, as amended ("PUHCA"), and exempts
QFs from most provisions of the Federal Power Act (the "FPA") and, except under
certain limited circumstances, state laws concerning rate or financial
regulation. These exemptions are important to us and our competitors. We believe
that each of the electricity generating projects in which we own an interest and
which operates as a QF power producer currently meets the requirements under
PURPA necessary for QF status.
PURPA provides two primary benefits to QFs. First, QFs generally are
relieved of compliance with extensive federal and state regulations that control
the financial structure of an electric generating plant and the prices and terms
on which electricity may be sold by the plant. Second, the FERC's regulations
promulgated under PURPA require that electric utilities purchase electricity
generated by QFs at a price based on the purchasing utility's "avoided cost,"
and that the utility sell back-up power to the QF on a non-discriminatory basis.
The term "avoided cost" is defined as the incremental cost to an electric
utility of electric energy or capacity, or both, which, but for the purchase
from QFs, such utility would generate for itself or purchase from another
source. The FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases of power at rates lower than the utility's
avoided costs. While public utilities are not explicitly required by PURPA to
enter into long-term power sales agreements, PURPA helped to create a regulatory
environment in which it has been common for long-term agreements to be
negotiated.
In order to be a QF, a cogeneration facility must produce not only
electricity, but also useful thermal energy for use in an industrial or
commercial process for heating or cooling applications in certain proportions to
the facility's total energy output and must meet certain energy efficiency
standards. A geothermal facility may qualify as a QF if it produces less than 80
megawatts of electricity. Finally, a QF (including a geothermal QF or other
qualifying small power producer) must not be controlled or more than 50% owned
by an electric utility or by most electric utility holding companies, or a
subsidiary of such a utility or holding company or any combination thereof.
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We endeavor to develop our projects, monitor compliance by the projects
with applicable regulations and choose our customers in a manner which minimizes
the risks of any project losing its QF status. Certain factors necessary to
maintain QF status are, however, subject to the risk of events outside our
control. For example, loss of a thermal energy customer or failure of a thermal
energy customer to take required amounts of thermal energy from a cogeneration
facility that is a QF could cause the facility to fail requirements regarding
the level of useful thermal energy output. Upon the occurrence of such an event,
we would seek to replace the thermal energy customer or find another use for the
thermal energy which meets PURPA's requirements, but no assurance can be given
that this would be possible.
If one of the facilities in which we have an interest should lose its
status as a QF, the project would no longer be entitled to the exemptions from
PUHCA and the FPA. This could also trigger certain rights of termination under
the facility's power sales agreement, could subject the facility to rate
regulation as a public utility under the FPA and state law and could result in
us inadvertently becoming an electric utility holding company by owning more
than 10% of the voting securities of, or controlling, a facility that would no
longer be exempt from PUHCA. This could cause all of our remaining projects to
lose their qualifying status, because QFs may not be controlled or more than 50%
owned by such electric utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements and financing agreements and result in
termination, penalties or acceleration of indebtedness under such agreements
such that loss of status may be on a retroactive or a prospective basis.
Under the Energy Policy Act of 1992, if a facility can be qualified as an
exempt wholesale generator ("EWG"), it will be exempt from PUHCA even if it does
not qualify as a QF. Therefore, another response to the loss or potential loss
of QF status would be to apply to have the project qualified as an EWG. However,
assuming this changed status would be permissible under the terms of the
applicable power sales agreement, rate approval from FERC would be required. In
addition, the facility would be required to cease selling electricity to any
retail customers (such as the thermal energy customer) to retain its EWG status
and could become subject to state regulation of sales of thermal energy. See
"Public Utility Holding Company Regulation."
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at avoided costs. We do not know whether such legislation will be passed or
what form it may take. We believe that if any such legislation is passed, it
would apply only to new projects. As a result, although such legislation may
adversely affect our ability to develop new projects, we believe it would not
affect our existing QFs. There can be no assurance, however, that any
legislation passed would not adversely impact our existing projects.
Public Utility Holding Company Regulation
Under PUHCA, any corporation, partnership or other legal entity which owns
or controls 10% or more of the outstanding voting securities of a "public
utility company" or a company which is a "holding company" for a public utility
company is subject to registration with the Securities and Exchange Commission
and regulation under PUHCA, unless eligible for an exemption. A holding company
of a public utility company that is subject to registration is required by PUHCA
to limit its utility operations to a single integrated utility system and to
divest any other operations not functionally related to the operation of that
utility system. Approval by the SEC is required for nearly all important
financial and business dealings of a registered holding company. Under PURPA,
most QFs are not public utility companies under PUHCA.
The Energy Policy Act of 1992, among other things, amends PUHCA to allow
EWGs, under certain circumstances, to own and operate non-QF electric generating
facilities without subjecting those producers to registration or regulation
under PUHCA. The effect of such amendments has been to enhance the development
of non-QFs which do not have to meet the fuel, production and ownership
requirements of PURPA. We believe that these amendments benefit us by expanding
our ability to own and operate facilities that do not qualify for QF status.
However, they have also resulted in increased competition by allowing utilities
to develop such facilities which are not subject to the constraints of PUHCA.
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Federal Natural Gas Transportation Regulation
We have an ownership interest in 25 gas-fired cogeneration projects. The
cost of natural gas is ordinarily the largest expense of a gas-fired project and
is critical to the project's economics. The risks associated with using natural
gas can include the need to arrange transportation of the gas from great
distances, including obtaining removal, export and import authority if the gas
is transported from Canada; the possibility of interruption of the gas supply or
transportation (depending on the quality of the gas reserves purchased or
dedicated to the project, the financial and operating strength of the gas
supplier, whether firm or non-firm transportation is purchased and the operating
of the gas pipeline); and obligations to take a minimum quantity of gas and pay
for it (i.e., take-and-pay obligations).
Pursuant to the Natural Gas Act, FERC has jurisdiction over the
transportation and storage of natural gas in interstate commerce. With respect
to most transactions that do not involve the construction of pipeline
facilities, regulatory authorization can be obtained on a self-implementing
basis. However, pipeline rates and terms and conditions for such services are
subject to continuing FERC oversight.
Federal Power Act Regulation
Under the FPA FERC is authorized to regulate the transmission of electric
energy and the sale of electric energy at wholesale in interstate commerce.
Unless otherwise exempt, any person that owns or operates facilities used for
such purposes is considered a "public utility" subject to FERC jurisdiction.
FERC regulation under the FPA includes approval of the disposition of utility
property, authorization of the issuance of securities by public utilities,
regulation of the rates, terms and conditions for the transmission or sale of
electric energy at wholesale in interstate commerce, the regulation of
interlocking directorates, a uniform system of accounts and reporting
requirements for public utilities.
FERC regulations implementing PURPA provide that a QF is exempt from
regulation under the foregoing provisions of the FPA. An EWG is not exempt from
the FPA and therefore an EWG that makes sales of electric energy at wholesale in
interstate commerce is subject to FERC regulation as a "public utility."
However, many of the regulations which customarily apply to traditional public
utilities have been waived or relaxed for power marketers, EWGs and other
non-traditional public utilities that lack market power. EWGs are regularly
granted authorization to charge market based rates, blanket authority to issue
securities, and waivers of FERC's requirements pertaining to accounts, reports
and interlocking directorates. Such action is intended to implement FERC's
policy to foster a more competitive wholesale power market.
Many of the generating projects in which Calpine owns an interest are
operated as QFs and are therefore exempt from FERC regulation under the FPA.
However, several of Calpine's generating projects are or will be EWGs subject to
FERC jurisdiction under the FPA. Several Calpine affiliates have been granted
authority to engage in sales at market based rates and to issue securities and
have also been granted the customary waivers of FERC regulations available to
non-traditional public utilities; however we cannot assure that such authorities
or waivers will be granted in the future to other affiliates.
STATE REGULATION
State public utility commissions ("PUCs") have historically had broad
authority to regulate both the rates charged by, and the financial activities
of, electric utilities operating in their states and to promulgate regulation
for implementation of PURPA. Since a power sales agreement becomes a part of a
utility's cost structure (generally reflected in its retail rates), power sales
agreements with independent electricity producers, such as EWGs, are potentially
under the regulatory purview of PUCs and in particular the process by which the
utility has entered into the power sales agreements. If a PUC has approved the
process by which a utility secures its power supply, a PUC is generally inclined
to "pass through" the expense associated with power purchase agreement with an
independent power producer to the utility's retail customer. However, a
regulatory commission under certain circumstances may disallow the full
reimbursement to a utility for the cost to purchase power from a QF or an EWG.
In addition, retail sales of electricity or thermal energy by an independent
power producer may be subject to PUC regulation depending on state law.
Independent power producers which are not QFs under PURPA, or EWGs pursuant to
the Energy Policy Act of 1992, are
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considered to be public utilities in many states and are subject to broad
regulation by a PUC, ranging from requirement of certificate of public
convenience and necessity to regulation of organizational, accounting, financial
and other corporate matters. States may assert jurisdiction over the siting and
construction of electric generating facilities including QFs and EWGs and, with
the exception of QFs, over the issuance of securities and the sale or other
transfer of assets by these facilities.
In the State of California, restructuring legislation was enacted in
September 1996 and was implemented in 1998. This legislation established an
Independent Systems Operator ("ISO") responsible for centralized control and
efficient and reliable operation of the state-wide electric transmission grid,
and a power exchange responsible for an efficient competitive electric energy
auction open on a non-discriminatory basis to all electric services providers.
Other provisions include the quantification and qualification of utility
stranded costs to be eligible for recovery through competitive transition
charges ("CTC"), market power mitigation through utility divestiture of fossil
generation plants, the unbundling and establishment of rate structure for
historical utility functions, the continuation of public purpose programs and
issues related to issuance of rate reduction bonds.
The CEC and the California Legislature have responsibility for development
of a competitive market mechanism for allocation and distribution of funds made
available by the legislation for enhancement of in-state renewable resource
technologies and public interest research and development programs. Funds are to
be available through the four-year transition period to a fully competitive
electric services industry.
In addition to the significant opportunity provided for power producers
such as us through implementation of customer choice (direct access), the
California restructuring legislation both recognizes the sanctity of existing
contracts (including QF power sales contracts), provides for mitigation of
utility horizontal market power through divestiture of fossil generation by
California public utilities and provides funds for continuation of public
services programs including fuel diversity through enhancement for in-state
renewable technologies (includes geothermal) for the four-year transition period
to a fully competitive electric services industry.
Other states in which we conduct operations either have implemented or are
actively considering similar restructuring legislation.
State PUCs also have jurisdiction over the transportation of natural gas by
local distribution companies ("LDCs"). Each state's regulatory laws are somewhat
different; however, all generally require the LDC to obtain approval from the
PUC for the construction of facilities and transportation services if the LDC's
generally applicable tariffs do not cover the proposed transaction. LDC rates
are usually subject to continuing PUC oversight.
REGULATION OF CANADIAN GAS
The Canadian natural gas industry is subject to extensive regulation by
governmental authorities. At the federal level, a party exporting gas from
Canada must obtain an export license from the Canadian National Energy Board
("NEB"). The NEB also regulates Canadian pipeline transportation rates and the
construction of pipeline facilities. Gas producers also must obtain a removal
permit or license from provincial authorities before natural gas may be removed
from the province, and provincial authorities may regulate intra-provincial
pipeline and gathering systems. In addition, a party importing natural gas into
the United States first must obtain an import authorization from the U.S.
Department of Energy.
ENVIRONMENTAL REGULATIONS
The exploration for and development of geothermal resources and natural gas
and the construction and operation of wellfields, pipelines and power projects
are subject to extensive federal, state and local laws and regulations adopted
for the protection of the environment and to regulate land use. The laws and
regulations applicable to us primarily involve the discharge of emissions into
the water and air and the use of water, but can also include wetlands
preservation, endangered species, waste disposal and noise regulations. These
laws and regulations in many cases require a lengthy and complex process of
obtaining licenses, permits and approvals from federal, state and local
agencies.
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Noncompliance with environmental laws and regulations can result in the
imposition of civil or criminal fines or penalties. In some instances,
environmental laws also may impose clean-up or other remedial obligations in the
event of a release of pollutants or contaminants into the environment. The
following federal laws are among the more significant environmental laws as they
apply to us. In most cases, analogous state laws also exist that may impose
similar, and in some cases more stringent, requirements on us as those discussed
below.
Clean Air Act
The Federal Clean Air Act of 1970 (the "Clean Air Act") provides for the
regulation, largely through state implementation of federal requirements, of
emissions of air pollutants from certain facilities and operations. As
originally enacted, the Clean Air Act sets guidelines for emissions standards
for major pollutants (i.e., sulfur dioxide and nitrogen oxide) from newly built
sources. In late 1990, Congress passed the Clean Air Act Amendments (the "1990
Amendments"). The 1990 Amendments attempt to reduce emissions from existing
sources, particularly previously exempted older power plants. We believe that
all of our operating plants are in compliance with federal performance standards
mandated for such plants under the Clean Air Act and the 1990 Amendments. With
respect to our Aidlin geothermal plant and one of our steam field pipelines, our
operations have, in certain instances, necessitated variances under applicable
California air pollution control laws. However, we believe that we are in
material compliance with such laws with respect to such facilities.
Clean Water Act
The Federal Clean Water Act (the "Clean Water Act") establishes rules
regulating the discharge of pollutants into waters of the United States. We are
required to obtain a wastewater and storm water discharge permit for wastewater
and runoff, respectively, from certain of our facilities. We believe that, with
respect to our geothermal operations, we are exempt from newly promulgated
federal storm water requirements. We believe that we are in material compliance
with applicable discharge requirements of the Clean Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act ("RCRA") regulates the
generation, treatment, storage, handling, transportation and disposal of solid
and hazardous waste. We believe that we are exempt from solid waste requirements
under RCRA. However, particularly with respect to its solid waste disposal
practices at the power generation facilities and steam fields located at The
Geysers, we are subject to certain solid waste requirements under applicable
California laws. We believe that our operations are in material compliance with
such laws.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which
there has been a release or threatened release of hazardous substances and
authorizes the United States Environmental Protection Agency to take any
necessary response action at Superfund sites, including ordering potentially
responsible parties ("PRPs") liable for the release to take or pay for such
actions. PRPs are broadly defined under CERCLA to include past and present
owners and operators of, as well as generators of wastes sent to, a site. As of
the present time, we are not subject to liability for any Superfund matters.
However, we generate certain wastes, including hazardous wastes, and sends
certain of our wastes to third party waste disposal sites. As a result, there
can be no assurance that we will not incur liability under CERCLA in the future.
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RISK FACTORS
SEE RISK FACTOR SECTION STARTING ON PAGE F-16 UNDER "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" INCLUDED IN APPENDIX
F TO THIS REPORT.
COMPETITION
The power generation industry is characterized by intense competition, and
we encounter competition from utilities, industrial companies and other
independent power producers. In recent years, there has been increasing
competition in an effort to obtain power sales agreements, and this competition
has contributed to a reduction in electricity prices. In addition, many states
are implementing or considering regulatory initiatives designed to increase
competition in the domestic power industry. In California, the CPUC issued
decisions which provide for direct access for all customers as of April 1, 1998.
In Texas, recently enacted legislation will phase-in a deregulated power market
commencing January 1, 2001. Regulatory initiatives are also being considered in
other states, including New York and states in New England. This competition has
put pressure on electric utilities to lower their costs, including the cost of
purchased electricity, and increasing competition in the supply of electricity
in the future will increase this pressure.
CUSTOMERS
A majority of our power generation facilities currently rely on one or more
power sales agreements with one or more utilities or other customers for all or
substantially all of such facility's revenue. In addition, during 1999, sales of
electricity to two utility customers, PG&E and TUEC, comprised approximately 47%
of our total revenue that year. The loss of any one power sales agreement with
any of these customers could have a negative effect on our results of
operations. In addition, any material failure by any customer to fulfill its
obligations under a power sales agreement could have a negative effect on the
cash flow available to us and on our results of operations.
SEASONALITY
Our results are subject to quarterly and seasonal fluctuations. Our
quarterly operating results have fluctuated in the past and may continue to do
so in the future as a result of a number of factors, including the timing and
size of acquisitions, the completion of development projects, and variations in
levels of production.
Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal. Our industry
generally experiences summer peaks and winter peaks, and depending on the
service territory, there may be seasonal variations experienced by electric
power generators in the industry.
EMPLOYEES
As of December 31, 1999, we employed 865 people. None of our employees are
covered by collective bargaining agreements, and we have never experienced a
work stoppage, strike or labor dispute. We consider relations with our employees
to be good.
ITEM 2. PROPERTIES
Our principal executive office is located in San Jose, California, under a
lease that expires in June 2006. We have regional offices in Pleasanton,
California; Houston, Texas; Boston, Massachusetts and Folsom, California.
We have leasehold interests in 105 leases comprising 21,217 acres of
federal, state and private geothermal resource lands in The Geysers area in
northern California. In the Glass Mountain and Medicine Lake areas in northern
California, we hold leasehold interests in 18 leases comprising approximately
25,028 acres of federal geothermal resource lands.
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In general, under the leases, we have the exclusive right to drill for,
produce and sell geothermal resources from these properties and the right to use
the surface for all related purposes. Each lease requires the payment of annual
rent until commercial quantities of geothermal resources are established. After
such time, the leases require the payment of minimum advance royalties or other
payments until production commences, at which time production royalties are
payable. Such royalties and other payments are payable to landowners, state and
federal agencies and others, and vary widely as to the particular lease. The
leases are generally for initial terms varying from 10 to 20 years or for so
long as geothermal resources are produced and sold. Certain of the leases
contain drilling or other exploratory work requirements. In certain cases, if a
requirement is not fulfilled, the lease may be terminated and in other cases
additional payments may be required. We believe that our leases are valid and
that we have complied with all the requirements and conditions material to the
continued effectiveness of the leases. A number of our leases for undeveloped
properties may expire in any given year. Before leases expire, we perform
geological evaluations in an effort to determine the resource potential of the
underlying properties. We cannot assure that we will decide to renew any
expiring leases.
We own Calpine Gas Company and CNGC, which have interests in property as
listed below. Based on an independent petroleum engineering report, as of
December 31, 1999, utilizing year end product prices and costs held constant,
our proved oil and natural gas reserve volumes, in thousands of barrels
("MBbls") and billion cubic feet ("Bcf") and associated future net reserves,
undiscounted and discounted at 10% ("PV 10") before future income taxes, are as
follows (dollars in thousands):
AS OF DECEMBER 31, 1999
-------------------------------------------------
OIL (MBBLS) GAS (BCF) UNDISCOUNTED PV 10
----------- --------- ------------ --------
Proved developed................... 1,304 190 $315,235 $165,318
Proved undeveloped................. 556 19 28,532 15,069
----- --- -------- --------
Total.................... 1,860 209 $343,767 $180,387
===== === ======== ========
Proved oil and natural gas reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Estimated
future development costs associated with proved developed non-producing and
proved undeveloped reserves for 1999 total $16.2 million.
The following table sets forth the undeveloped acreage, developed acreage
and productive wells in which we own a working interest as of December 31, 1999.
Productive wells are wells in which we have a working interest and are capable
of producing oil or natural gas. Gross represents the total number of acres or
wells in which we own a working interest. Net represents our proportionate
working interest resulting from our ownership in the gross acres or wells.
UNDEVELOPED ACRES DEVELOPED ACRES PRODUCTIVE WELLS
----------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
------- ------ ------- ------ ------- -----
Arkansas.............................. -- -- 5,623 1,669 46 21
California............................ 48,619 36,731 40,588 38,101 141 124
Colorado.............................. -- -- 2,794 511 -- --
Louisiana............................. 42,558 41,542 8,323 5,860 20 9
Mississippi........................... 350 277 9,625 2,874 17 5
Oklahoma.............................. 4,765 953 16,678 7,629 63 18
Texas................................. 17,481 7,123 17,347 9,957 102 59
------- ------ ------- ------ --- ---
Total....................... 113,773 86,626 100,978 66,601 389 236
======= ====== ======= ====== === ===
We own the Texas City, Clear Lake and Pasadena Power Plants, which lease an
aggregate of 48 acres.
We own 40 gross acres and 38 net acres in Edinburg, Texas where we are
constructing the Magic Valley Power Plant.
We own 77 acres in Sutter County, California, on which the Greenleaf 1
Power Plant is located.
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See "Description of Facilities" for a description of the other material
leased or owned properties in which we have an interest. We believe that our
properties are adequate for our current operations.
ITEM 3. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including us. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of
a 50% interest in Auburndale Power Plant Partners Limited Partnership from
Norweb Power Services (No. 1) Limited. Indeck is claiming that Calpine
Gordonsville, Inc., Calpine Auburndale, Inc. and Calpine Corporation tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In July 1998, the court granted motions to dismiss,
without prejudice, the claims against Calpine Gordonsville, Inc. and Calpine
Auburndale, Inc. In August 1998, Indeck filed an amended complaint and the
defendants filed motions to dismiss. In April 1999, the court dismissed the
claims against Calpine Auburndale and Calpine Gordonsville with prejudice.
Indeck appealed the court's decision. The outcome of the appeal is not expected
until late 2000. We are unable to predict the outcome of these proceedings but
we do not expect that the outcome of these proceedings will have a material
adverse effect on our financial position or results of operation.
An action was filed against Lockport Energy Associates ("LERA") and the New
York Public Service Commission ("NYPSC") in August 1997 by NYSEG in the Federal
District Court for the Northern District of New York. NYSEG has requested the
Court to direct NYPSC and FERC to modify contract rates to be paid to the
Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that
the FERC violated PURPA and the Federal Power Act by failing to reform the NYSEG
contract that was previously approved by the NYPSC. We are unable to predict the
outcome of these proceedings but we do not expect that the outcome of these
proceedings will have a material adverse effect on our financial position or
results of operation. In any event, we retain the right to require The Brooklyn
Union Gas Company to purchase our interest in the Lockport Power Plant for $18.9
million, less equity distributions received by us, at any time before December
19, 2001.
We and our affiliates are involved in various other claims and legal
actions arising out of the normal course of business. We are unable to predict
the outcome of these proceedings but we do not expect that the outcome of these
proceedings will have a material adverse effect on our financial position or
results of operation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required hereunder is set forth under "Quarterly
Consolidated Financial Data" included in Appendix F, Note 17 of the Notes to
Consolidated Financial Statements to this report. The Company made no sales of
unregistered securities in the last three years except as follows:
Effective September 1999, Calpine Corporation amended its Retirement
Savings Plan to add a Calpine Common Stock Fund as one of the investment options
for employee contributions to the Plan. As the result of this amendment, the
exemption from registration under the Securities Act of 1933 for both the plan
participation interests and the shares of Common Stock previously afforded by
Section 3(a)(2) of the Securities Act ceased to be available.
Since the Plan amendment, through February 2000, Calpine estimates that (i)
the Plan has sold to participants $14.0 million in plan participation interests
and (ii) Calpine has sold to participants 155,566 shares of Common Stock, in
each case without the registration of the securities under the Securities Act.
26
27
Because employee contributions that are directed to the Calpine Common Stock
Fund are used by the Plan's trustee to purchase shares of Common Stock in the
open market, Calpine does not receive any proceeds from the sale of the shares.
While Calpine believes that many of the sales would qualify as an exempt
transaction under Section 4(2) of the Securities Act, it has not undertaken an
evaluation of the eligibility of each Plan participant to purchase securities in
a private placement, and expects that such an evaluation would show that not all
of the Plan participants who purchased unregistered securities would qualify.
Accordingly, Calpine in March 2000, intends to file with the Securities and
Exchange Commission a registration statement on Form S-8 registering both the
plan participation interest and shares of Common Stock for future issuance under
the Plan. Calpine is prepared to rescind any sale of plan participation
interests or common stock if requested by a participant who did not qualify for
a private placement.
ITEM 6. SELECTED FINANCIAL DATA
The information required hereunder is set forth under "Selected
Consolidated Financial Data" included in Appendix F to this report.
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included in Appendix F to this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Financial Market Risks" included in Appendix F to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is set forth under "Report of
Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated
Statements of Operations," "Consolidated Statements of Shareholder's Equity,"
"Consolidated Statements of Cash Flows," and "Notes to Consolidated Financial
Statements" included in Appendix F of this report. Other financial information
and schedules are included in Appendix F of this report.
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 2000 Annual
Meeting of Shareholders to be filed.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 2000 Annual
Meeting of Shareholders to be filed.
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 2000 Annual
Meeting of Shareholders to be filed.
27
28
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)-1. FINANCIAL STATEMENTS AND OTHER INFORMATION
The following items appear in Appendix F of this report:
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition and Results
of Operations
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 1999 and 1998
Consolidated Statements of Operations for the Years Ended December 31,
1999, 1998 and 1997
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 1998 and 1997
Notes to Consolidated Financial Statements for the Years Ended December
31, 1999, 1998 and 1997
(a)-2. FINANCIAL STATEMENT SCHEDULES
None
(a)-3. REPORTS ON FORM 8-K
1. Current report dated October 11, 1999 and filed on October 12, 1999
ITEM 5. OTHER EVENTS -- Press Release announcing Calpine Corporation's
expectation of higher Financial Results for the
Three and Nine Months Ended September 30, 1999.
2. Current report dated October 22, 1999 and filed on October 25, 1999
ITEM 5. OTHER EVENTS -- Press Release announcing Calpine Corporation's
Financial Results for the Three and Nine Months
Ended September 30, 1999
3. Current report dated January 26, 2000 and filed on February 8, 2000
ITEM 5. OTHER EVENTS -- Announcement of Pricing of Up to $360 Million of
Convertible Preferred Securities
4. Current report dated February 3, 2000 and filed on February 8, 2000
ITEM 5. OTHER EVENTS -- Press Release announcing Calpine Corporation's
Financial Results for the Three and Twelve
Months Ended December 31, 1999
28
29
(a)-4. EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(b)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(b)
4.1 -- Indenture dated as of February 17, 1994 between the Company
and Shawmut Bank of Connecticut, National Association, as
Trustee, including form of Notes.(a)
4.2 -- Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(c)
4.3 -- Indenture dated as of July 8, 1997 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(e)
4.4 -- Indenture dated as of March 31, 1998 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(g)
4.5 -- Indenture dated as of March 26, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.6 -- Indenture dated as of April 21, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.7 -- 1999 HIGH TIDES.
4.7.1 -- Certificate of Trust of Calpine Capital Trust, a Delaware
statutory trust, filed October 4, 1999.(i)
4.7.2 -- Corrected Certificate of Certificate of Trust of Calpine
Capital Trust, a Delaware statutory trust, dated September
29, 1999.(i)
4.7.3 -- Declaration of Trust of Calpine Capital Trust, dated as of
October 4, 1999, among Calpine Corporation, as Depositor,
The Bank of New York (Delaware), as Delaware Trustee, The
Bank of New York, as Property Trustee, and the
Administrative Trustees named therein.(i)
4.7.4 -- Indenture, dated as of November 2, 1999, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(i)
4.7.5 -- Remarketing Agreement, dated November 2, 1999, among Calpine
Corporation, Calpine Capital Trust, The Bank of New York, as
Tender Agent, and Credit Suisse First Boston Corporation, as
Remarketing Agent.(i)
4.7.6 -- Amended and Restated Declaration of Trust of Calpine Capital
Trust, dated as of November 2, 1999, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, and The Bank of
New York, as Property Trustee, and the Administrative
Trustees named therein, including form of Preferred Security
and form of Common Security.(i)
4.7.7 -- Preferred Securities Guarantee Agreement, dated as of
November 2, 1999, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(i)
4.8 -- 2000 HIGH TIDES.
4.8.1 Certificate of Trust of Calpine Capital Trust II, a Delaware
statutory trust, filed January 25, 2000.(*)
4.8.2 Declaration of Trust of Calpine Capital Trust II, dated as
of January 24, 2000, among Calpine Corporation, as Depositor
and Debenture Issuer, The Bank of New York (Delaware), as
Delaware Trustee, The Bank of New York, as Property Trustee,
and the Administrative Trustees named therein.(*)
29
30
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
4.8.3 Indenture, dated as of January 31, 2000, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(*)
4.8.4 Remarketing Agreement, dated as of January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, The Bank of
New York, as Tender Agent, and Credit Suisse First Boston
Corporation, as Remarketing Agent.(*)
4.8.5 Registration Rights Agreement, dated January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, Credit Suisse
First Boston Corporation and ING Barings LLC.(*)
4.8.6 Amended and Restated Declaration of Trust of Calpine Capital
Trust II, dated as of January 31, 2000, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, The Bank of New
York, as Property Trustee, and the Administrative Trustees
named therein, including form of Preferred Security and form
of Common Security.(*)
4.8.7 -- Preferred Securities Guarantee Agreement, dated as of
January 31, 2000, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(*)
10.1 -- Purchase Agreements.
10.1.1 -- Purchase and Sale Agreement dated March 27, 1997 for the
purchase and sale of shares of Enron/Dominion Cogen Corp.
Common Stock among Enron Power Corporation and Calpine
Corporation.(f)
10.1.2 -- Stock Purchase and Redemption Agreement dated March 31,
1998, among Dominion Cogen, Inc. Dominion Energy, Inc. and
Calpine Finance.(f)
10.2 Financing Agreements.
10.2.1 Calpine Construction Finance Company Financing
Agreement.(j)(*)
10.3 -- Other Agreements.
10.3.1 -- Calpine Corporation Stock Option Program and forms of
agreements thereunder.(a)
10.3.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements thereunder.(b)
10.3.3 -- Calpine Corporation Employee Stock Purchase Plan and forms
of agreements thereunder.(b)
10.3.4 -- Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(*)
10.3.5 -- Executive Vice President Employment Agreement between
Calpine Corporation and Ms. Ann B. Curtis.(k)
10.3.6 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A. Walter.(k)
10.3.7 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D. Kelly.(k)
10.3.8 -- Executive Vice President Employment Agreement between
Calpine Corporation and Mr. Thomas R. Mason.(k)
10.4 -- Form of Indemnification Agreement for directors and
officers.(b)
21 -- Subsidiaries of the Company.(*)
23 -- Consent of Arthur Andersen, LLP, Independent Public
Accountants.(*)
27 -- Financial Data Schedule.(*)
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 333-07497).
30
31
(c) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, and filed on March 27, 1996.
(e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(f) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
(g) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-61047).
(h) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-72583).
(i) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-87427).
(j) Approximately 200 pages of this exhibit have been omitted pursuant to a
request for confidential treatment. The omitted language has been filed
separately with the Securities and Exchange Commission.
(k) Incorporated by reference to Registrant's Form 10-Q/A dated September 30,
1999, and filed on November 17, 1999.
(*) Filed herewith.
31
32
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned thereunto duly authorized.
Date: February 28, 2000 CALPINE CORPORATION
By /s/ ANN B. CURTIS
------------------------------------
Ann B. Curtis
Executive Vice President and
Director
(Principal Financial Officer)
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS:
That the undersigned officers and directors of Calpine Corporation do
hereby constitute and appoint Peter Cartwright and Ann B. Curtis, and each of
them, the lawful attorney and agent or attorneys and agents with power and
authority to do any and all acts and things and to execute any and all
instruments which said attorneys and agents, or either of them, determine may be
necessary or advisable or required to enable Calpine Corporation to comply with
the Securities and Exchange Act of 1934, as amended, and any rules or
regulations or requirements of the Securities and Exchange Commission in
connection with this Form 10-K Annual Report. Without limiting the generality of
the foregoing power and authority, the powers granted include the power and
authority to sign the names of the undersigned officers and directors in the
capacities indicated below to this Form 10-K Annual Report or amendments or
supplements thereto, and each of the undersigned hereby ratifies and confirms
all that said attorneys and agents, or either of them, shall do or cause to be
done by virtue hereof. This Power of Attorney may be signed in several
counterparts.
IN WITNESS WHEREOF, each of the undersigned has executed this Power of
Attorney as of the date indicated opposite the name.
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ PETER CARTWRIGHT Chairman, President, Chief February 28, 2000
- ----------------------------------------------------- Executive and Director
Peter Cartwright (Principal Executive Officer)
/s/ ANN B. CURTIS Executive Vice President and February 28, 2000
- ----------------------------------------------------- Director (Principal Financial
Ann B. Curtis Officer)
/s/ CHARLES B. CLARK, JR. Vice President and Corporate February 28, 2000
- ----------------------------------------------------- Controller (Principal
Charles B. Clark, Jr. Accounting Officer)
/s/ JEFFREY E. GARTEN Director February 28, 2000
- -----------------------------------------------------
Jeffrey E. Garten
/s/ SUSAN C. SCHWAB Director February 28, 2000
- -----------------------------------------------------
Susan C. Schwab
/s/ GEORGE J. STATHAKIS Director February 28, 2000
- -----------------------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director February 28, 2000
- -----------------------------------------------------
John O. Wilson
/s/ V. ORVILLE WRIGHT Director February 28, 2000
- -----------------------------------------------------
V. Orville Wright
32
33
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 1999
PAGE
----
Selected Consolidated Financial Data........................ F-2
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. F-4
Report of Independent Public Accountants.................... F-26
Consolidated Balance Sheets December 31, 1999 and 1998...... F-27
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997.......................... F-28
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1999, 1998 and 1997.............. F-29
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997.......................... F-30
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1999, 1998 and 1997.................... F-31
F-1
34
CALPINE CORPORATION AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT EARNINGS PER SHARE AND RATIO DATA)
YEARS ENDED DECEMBER 31,
--------------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- --------
STATEMENT OF OPERATIONS DATA:
REVENUE:
Electricity and steam sales................. $127,799 $199,464 $237,277 $507,897 $760,325
Service contract revenue.................... 7,153 6,455 10,177 20,249 43,773
(Loss) income from unconsolidated
investments in power projects............. (2,854) 6,537 15,819 25,240 36,593
Interest income on loans to power
projects.................................. -- 2,098 13,048 2,562 1,226
Other revenue............................... -- -- -- -- 5,818
-------- -------- -------- -------- --------
Total revenue........................ 132,098 214,554 276,321 555,948 847,735
Cost of revenue............................. 77,388 129,200 153,308 375,327 557,477
-------- -------- -------- -------- --------
Gross profit.............................. 54,710 85,354 123,013 180,621 290,258
Project development expenses................ 3,087 3,867 7,537 7,165 10,712
General and administrative expenses......... 8,937 14,696 18,289 26,780 53,044
-------- -------- -------- -------- --------
Income from operations.................... 42,686 66,791 97,187 146,676 226,502
Interest expense............................ 32,154 45,294 61,466 86,726 91,162
Distributions on trust preferred
securities................................ -- -- -- -- 2,565
Other income................................ (1,895) (6,259) (17,438) (13,423) (25,441)
-------- -------- -------- -------- --------
Income before provision for income
taxes................................... 12,427 27,756 53,159 73,373 158,216
Provision for income taxes.................. 5,049 9,064 18,460 27,054 61,973
-------- -------- -------- -------- --------
Income before extraordinary charge........ 7,378 18,692 34,699 46,319 96,243
Extraordinary charge, net of tax benefit of
$ -- , $ -- , $ -- , $441 and $793........ -- -- -- 641 1,150
-------- -------- -------- -------- --------
Net income................................ $ 7,378 $ 18,692 $ 34,699 $ 45,678 $ 95,093
======== ======== ======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock
Outstanding............................. 20,776 25,805 39,892 40,242 52,328
Income before extraordinary charge........ $ 0.36 $ 0.72 $ 0.87 $ 1.15 $ 1.84
Extraordinary charge...................... $ -- $ -- $ -- $ (0.01) $ (0.02)
Net income................................ $ 0.36 $ 0.72 $ 0.87 $ 1.14 $ 1.82
Diluted earnings per common share:
Weighted average shares of common stock
Outstanding............................. 21,913 29,758 42,032 42,328 55,661
Income before extraordinary charge........ $ 0.34 $ 0.63 $ 0.83 $ 1.09 $ 1.73
Extraordinary charge...................... -- -- -- $ (0.01) $ (0.02)
Net income................................ $ 0.34 $ 0.63 $ 0.83 $ 1.08 $ 1.71
OTHER FINANCIAL DATA AND RATIOS:
Depreciation and amortization............... $ 26,896 $ 40,551 $ 48,935 $ 82,913 $ 83,040
EBITDA(1)................................... $ 69,515 $117,379 $172,616 $255,306 $392,160
EBITDA to Consolidated Interest
Expense(2)................................ 2.11x 2.41x 2.60x 2.74x 3.79x
Total debt to EBITDA........................ 5.87x 5.12x 4.96x 4.20x 5.24x
Ratio of earnings to fixed charges(3)....... 1.46x 1.45x 1.64x 1.68x 1.78x
F-2
35
AS OF DECEMBER 31,
------------------------------------------------------------
1995 1996 1997 1998 1999
-------- ---------- ---------- ---------- ----------
BALANCE SHEET DATA:
Cash and cash equivalents..................... $ 21,810 $ 95,970 $ 48,513 $ 96,532 $ 349,371
Property, plant and equipment, net............ 447,751 648,208 736,339 1,094,303 2,866,447
Investment in power projects.................. 8,218 13,936 222,542 221,509 284,834
Total assets........................... 554,531 1,031,397 1,380,915 1,728,946 3,991,606
Short-term debt............................... 85,885 37,492 112,966 5,450 11,638
Borrowings under line of credit, current
portion..................................... 19,851 -- -- -- 35,832
Borrowings under line of credit, net of
current portion............................. -- -- -- -- 86,918
Non-recourse project financing (long-term).... 190,642 278,640 182,893 114,190 357,137
Notes payable, net of current................. 6,348 -- -- -- 10,385
Senior notes.................................. 105,000 285,000 560,000 951,750 1,551,750
Total debt............................. 407,726 601,132 855,859 1,071,390 2,053,660
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust............................ -- -- -- -- 270,713
Minority interests............................ -- -- -- -- 61,705
Stockholders' equity.......................... 25,227 203,127 239,956 286,966 964,632
(The information contained in the Selected Consolidated Financial Data is
derived from the audited Consolidated Financial Statements of Calpine
Corporation and Subsidiaries.)
- ---------------
(1) EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments
in power projects, reduced by the income from unconsolidated investments in
power projects. EBITDA is presented not as a measure of operating results,
but rather as a measure of our ability to service debt. EBITDA should not be
construed as an alternative to either (i) income from operations (determined
in accordance with generally accepted accounting principles) or (ii) cash
flows from operating activities (determined in accordance with generally
accepted accounting principles).
(2) Consolidated Interest Expense is defined as total interest expense plus
one-third of all operating lease obligations, dividends paid in respect of
preferred stock and cash contributions to any employee stock ownership plan
used to pay interest on loans incurred to purchase our capital stock.
(3) Earnings are defined as income before provision for taxes, extraordinary
charge and cumulative effect of change in accounting principle plus cash
received from investments in power projects and fixed charges reduced by the
equity in income from investments in power projects and capitalized
interest. Fixed charges consist of interest expense, capitalized interest,
amortization of debt issuance costs and the portion of rental expenses
representative of the interest expense component.
F-3
36
CALPINE CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding our intent, belief or current
expectations. Prospective investors are cautioned that any such forward-looking
statements are not guarantees of future performance and involve a number of
risks and uncertainties; actual results could differ materially from those
indicated by such forward-looking statements. Among the important factors that
could cause actual results to differ materially from those indicated by such
forward-looking statements are: (i) that the information is of a preliminary
nature and may be subject to further adjustment, (ii) the possible
unavailability of financing, (iii) risks related to the development, acquisition
and operation of power plants, (iv) the impact of avoided cost pricing, energy
price fluctuations and gas price increases, (v) the impact of curtailment, (vi)
the seasonal nature of our business, (vii) start-up risks, (viii) general
operating risks, (ix) the dependence on third parties, (x) risks associated with
international investments, (xi) risks associated with the power marketing
business, (xii) changes in government regulation, (xiii) the availability of
natural gas, (xiv) the effects of competition, (xv) the dependence on senior
management, (xvi) volatility in the our stock price, (xvii) fluctuations in
quarterly results and seasonality, and (xviii) other risks identified from time
to time in our reports and registration statements filed with the Securities and
Exchange Commission.
OVERVIEW
Calpine is engaged in the development, acquisition, ownership, and
operation of power generation facilities and the sale of electricity and steam
principally in the United States. At February 23, 2000, we had interests in 44
power plants and steam fields predominantly in the United States, having an
aggregate capacity of 4,273 megawatts.
On January 4, 1999, we completed the acquisition of a 20% interest in
approximately 82 billion cubic feet of proven natural gas reserves located in
the Sacramento basin of Northern California. We paid approximately $14.9 million
for $13.0 million in redeemable non-voting preferred stock and 20% of the
outstanding common stock of Sheridan California Energy, Inc. ("SCEI").
Additionally, we signed a ten year gas contract enabling us to purchase 100% of
SCEI's production.
On February 17, 1999, we announced that the Delta Energy Center met the
California Energy Commission's ("CEC") Data Adequacy requirements. This ruling
stated that our Application for Certification contained adequate information for
the CEC to begin its analysis of the power plant's environmental impacts and
proposed mitigation. The Delta Energy Center, an 880 megawatt gas-fired power
plant located at the Dow Chemical Company facility in Pittsburg, California, is
the first power plant that will be developed, owned and operated under a joint
venture with Bechtel Enterprises, and will provide power to the Pittsburg,
California and the greater San Francisco Bay Area. The gas-fired power plant is
to be constructed by Bechtel and operated by us.
On February 17, 1999, we announced plans to develop, own and operate a 545
megawatt gas-fired power plant in Westbrook, Maine. We acquired the development
rights for the Westbrook Energy Center from Genesis Power Corporation. This
power plant is scheduled to begin power deliveries in early 2001, and will serve
the New England market.
On February 24, 1999, we announced plans to develop, own and operate a 600
megawatt gas-fired power plant located in San Jose, California. This power
plant, called the Metcalf Energy Center, is the second power plant to be
developed under the joint venture with Bechtel Enterprises, and will provide
electricity to the San Francisco Bay area. We expect the plant to commence
operation in mid 2002.
F-4
37
On March 19, 1999, we completed the acquisition of Unocal Corporation's
Geysers geothermal steam fields in northern California for approximately $102.2
million. The steam fields fuel our 12 Sonoma County power plants, totaling 544
megawatts of capacity. We purchased these plants from Pacific Gas and Electric
Company ("PG&E") on May 7, 1999.
On April 14, 1999, we received approval from the CEC to construct a 545
megawatt gas-fired power plant near Yuba City, California. This power plant,
called the Sutter Power Plant, was the first new power plant approved in
California's deregulated power industry. Electricity produced by the Sutter
Power Plant will be sold into California's energy market. We expect the plant to
commence operation in mid 2001.
On April 22, 1999, we entered into a joint venture with GenTex Power
Corporation to develop, own and operate a 545 megawatt gas-fired power plant in
Bastrop County, Texas, called Lost Pines I. Construction of this power plant
began in October 1999. Under the definitive agreements we entered in September
1999, we will manage all phases of the plant's development process, with GenTex
and ourselves jointly operating the plant. The output from Lost Pines I will be
divided equally, with GenTex selling its portion to its customer base, while we
will sell our portion to the wholesale power market in Texas. We expect the
plant to commence operation in mid-2001.
On April 23, 1999, we entered into a joint agreement with Pinnacle West
Capital Corporation to develop, own and operate a 545 megawatt gas-fired power
plant located in Phoenix, Arizona. This plant, called the West Phoenix Power
Plant, will provide power to the Phoenix metropolitan area. The timing of
development activities is still under discussion with our partner.
On May 7, 1999, we completed the acquisitions from PG&E of 12 Sonoma County
and 2 Lake County power plants for approximately $212.8 million. The
acquisitions were financed with a 24-year operating lease. Our geothermal steam
fields fuel the facilities, which have a combined capacity of approximately 694
megawatts of electricity. All of the generation from the facilities is sold to
the California power exchange, with the exception of an agreement entered into
on April 29, 1999, to sell to Commonwealth Energy Corporation 75 megawatts of
geothermal electricity in 1999, 100 megawatts in 2000, and 125 megawatts in 2001
and through June 2002. Historically, we have served as a steam supplier for
these facilities, which had been owned and operated by PG&E. These acquisitions
have enabled us to consolidate our operations in The Geysers into a single
ownership structure and to integrate the power plant and steam field operations,
allowing us to optimize the efficiency and performance of the facilities. We
believe that these acquisitions provide us with significant synergies that
leverage our expertise in geothermal power generation and position us to benefit
from the demand for "green" energy in the competitive market.
On June 21, 1999, we acquired the rights to build, own and operate a 545
megawatt gas-fired power plant located in Ontelaunee Township, Pennsylvania. The
plant, called the Ontelaunee Energy Center, will provide power to residences and
businesses throughout the Pennsylvania-New Jersey-Maryland power pool.
Construction will commence in 2000 and the plant is scheduled to begin
production in 2002.
On July 8, 1999, we announced a renegotiation of our Gilroy power sales
agreement with PG&E. The amendment provides for the termination of the remaining
18 years of the long-term contract in exchange for fixed long-term payments by
PG&E to us. The amended agreement was approved by the California Public
Utilities Commission on December 2, 1999. We will continue to sell the output
from the Gilroy Power Plant through October 2002 to PG&E and thereafter we will
market the output in the California wholesale power market.
On August 20, 1999, we announced the purchase of 18 F-class combustion
turbines from Siemens Westinghouse Power Corporation that will be capable of
producing 4,900 megawatts of electricity in a combined-cycle configuration.
Beginning in 2002, Siemens will deliver six turbines per year through 2004.
Combined with our existing turbine orders we have 69 turbines under contract,
option, letter of intent or other commitment capable of producing approximately
18,800 megawatts in a combined-cycle mode.
On August 31, 1999, we completed the acquisition of an additional 50% of
the Aidlin Power Plant from Edison Mission Energy (5%) and General Electric
Capital Corporation (45%) for a total purchase price of $7.2 million. We now own
55% of the 20-megawatt Aidlin Power Plant.
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On September 20, 1999, the Board of Directors authorized a two-for-one
stock split of our common stock, in the form of a stock dividend, effective
October 7, 1999, payable to stockholders of record on September 28, 1999. In the
Management's Discussion and Analysis, all references to the number of common
shares and per share amounts have been adjusted for this split.
On September 29, 1999 we completed the acquisition of development rights to
build, own and operate the Los Medanos Power Plant from Enron North America. The
Los Medanos Power Plant is a 500 megawatt gas-fired cogeneration plant located
adjacent to USS-POSCO Industries steel mill in Pittsburg, California. Los
Medanos will supply USS-POSCO with 60 megawatts of electricity and 75,000 pounds
per hour of steam, and market the excess electricity into the California power
exchange and under bilateral contracts. Construction commenced in September 1999
and commercial operation is scheduled to occur in 2001.
On September 30, 1999 we announced plans to build, own and operate an 800
megawatt gas-fired cogeneration power plant at Bayer Corporation's chemical
facility in Baytown, Texas. The Baytown Power Plant will supply Bayer with all
of its electric and steam requirements for 20 years and market excess
electricity into the Texas wholesale power market. Construction is estimated to
commence in 2000 and commercial operation in late 2001.
On October 1, 1999, we completed the acquisition of Sheridan Energy, Inc.,
a natural gas exploration and production company, through a $38.8 million cash
tender offer. We purchased all of the outstanding shares of Sheridan Energy's
common stock for $5.50 per share. In addition, we redeemed $11.9 million of
outstanding preferred stock of Sheridan Energy. Sheridan Energy's oil and gas
properties, including approximately 148 billion cubic feet equivalent of proven
reserves as of July 1, 1999 and certain leasehold acreage, are located in
northern California and the Gulf Coast region, where we are developing low-cost
natural gas supplies and proprietary pipeline systems to support our
strategically-located natural gas-fired power plants. We subsequently renamed
Sheridan Energy as Calpine Natural Gas Company ("CNGC").
On October 19, 1999, we completed the acquisition of the Calistoga Power
Plant from FPL Energy and Caithness Corporation for approximately $77.9 million.
Located in The Geysers region of northern California, Calistoga is a 67 megawatt
facility which provides electricity to PG&E under a long-term contract.
On October 25, 1999, we announced that we had executed a letter of intent
which gives us the exclusive right to negotiate with LYONDELL-CITGO Refining LP
to build, own and operate a 560 megawatt gas-fired cogeneration power plant at
the LYONDELL-CITGO refinery in Houston, Texas. The Channel Energy Center will
supply all of the electricity and steam requirements for 20 years to the
refinery. Permitting for the facility is currently underway, with construction
projected to commence in early 2000 and commercial operation in 2001.
On October 27, 1999, we completed a public offering of 8,280,000 shares of
our common stock at $46.31 per share and 5,520,000 5 3/4% HIGH TIDES issued by a
subsidiary trust at $50.00 each, raising $636.7 million of aggregate net
proceeds.
On November 3, 1999, we completed the acquisition of development rights to
build, own and operate the Towantic Energy Center. The Towantic Energy Center is
a 500 megawatt gas-fired cogeneration plant located in Oxford, Connecticut. The
Towantic Energy Center will market its electricity via bilateral contracts into
the New England region. Construction is estimated to commence in 2000 and
commercial operation in 2002.
On November 3, 1999, we executed an agreement with Credit Suisse First
Boston, New York branch, and The Bank of Nova Scotia, as lead arrangers, for a
$1.0 billion non-recourse revolving construction credit facility. We will use
this non-recourse credit facility to finance the construction of our diversified
portfolio of gas-fired power plants currently under development.
On December 17, 1999, we acquired 80% of the common stock of Cogeneration
Corporation of America, Inc. ("CGCA") for $25.00 per share or approximately
$137.3 million. NRG Energy, Inc., a wholly owned subsidiary of Northern States
Power, owns the remaining 20%. CGCA owns interests in six natural gas-fired
power plants, totaling 579 megawatts. The plants are located in Pennsylvania,
New Jersey, Illinois and Oklahoma.
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On December 31, 1999, but effective as of November 1, 1999, we completed
the acquisition of Vintage Petroleum, Inc.'s interest in the Rio Vista Gas Unit
and related areas for approximately $71.5 million. As of the effective date of
the acquisition, Vintage owned approximately 90 billion cubic feet of proven
natural gas reserves and certain leasehold acreage located in the Sacramento
Basin in northern California. As a result of this acquisition and the Sheridan
Energy acquisition, we own a 99.5% working interest in the Rio Vista Gas Unit
and certain development acreage in northern California.
TRANSACTIONS ANNOUNCED OR CONSUMMATED SUBSEQUENT TO DECEMBER 31, 1999
On January 11, 2000, we announced our plans to expand our presence into the
Florida wholesale power market. Our plans are to invest approximately $750
million in power generation facilities and manage these development activities
in the Southeast from a new office in Tampa, Florida. We will develop two
natural gas-fired energy centers, the 1,080 megawatt Blue Heron Energy Center,
to be located outside of Vero Beach, and the 540 megawatt Osprey Energy Center,
to be located in the City of Auburndale adjacent to an existing power facility
in which we have an interest.
Construction for the proposed facilities is planned for 2001, with the
Osprey project to commence operation in early 2003, followed by the Blue Heron
Energy Center in mid-2003.
On January 14, 2000, we acquired a 50% interest in the Aries Power Plant, a
600 megawatt natural gas-fired plant currently under construction near Pleasant
Hill, Missouri, from a subsidiary of Aquila Energy Corporation. Construction
started in October 1999. Commercial operation of the first 330 megawatts is
scheduled to begin June 2001 with the balance of the plant starting in January
2002. The majority of the facility's output will be sold to Missouri Public
Service through May 2005. Thereafter, power will be sold into the Southwest
Power Pool.
On January 18, 2000, we entered into an agreement to provide the Sacramento
Municipal Utility District ("SMUD") with a five year supply of electricity from
our 545-megawatt Sutter Power Plant. The plant is currently under construction
near Yuba City, California. We will provide 150 megawatts of electricity to
SMUD's customer base beginning with the plant's startup in mid-2001.
On January 26, 2000, we completed an offering under Rule 144A of the
Securities Act of 6,000,000 5 1/2% HIGH TIDES issued by a subsidiary trust at
$50.00 each, raising $292.4 million of aggregate net proceeds. In February 2000,
we sold an additional 1,200,000 5 1/2% HIGH TIDES pursuant to the exercise of
the underwriters' over-allotment option for net proceeds of approximately $58.6
million.
On January 28, 2000, we acquired the development rights for the Hermiston
Power Plant, a 540 megawatt gas-fired cogeneration power facility located near
Hermiston, Oregon, from Ida-West Energy Company and TransCanada Pipelines.
Construction of the facility is expected to commence in the summer of 2000 with
commercial operation commencing in 2002.
On February 2, 2000, we announced plans to build, own and operate the
Decatur Energy Center, a 700 megawatt gas-fired cogeneration power plant at
Solutia Inc.'s Decatur, Alabama chemical facility. Under terms of a 20 year
contract, Solutia will lease a portion of the facility to meet its electricity
needs and purchase its steam requirements from us. Excess power from the
facility will be sold into the Southeastern wholesale power market under a
variety of short, mid, and long term contracts. We will also build a new
intrastate natural gas pipeline to fuel the plant. Construction is scheduled to
commence in 2000 with commercial operations commencing in 2002.
On February 4, 2000, we acquired 100% of the stock of Western Gas Resources
California ("Western") from Western Gas Resources, Inc. for $14.9 million.
Western's assets include the 130-mile Steelhead natural gas pipeline and the
remaining interest in the Sacramento River Gas System ("SRGS") natural gas
pipeline, now 100% owned by us.
On February 8, 2000, we announced that the Towantic Energy Center received
approval through a townwide referendum to purchase the town-owned land on which
the facility will be built. The referendum
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also approved a Tax Stabilization Agreement that will even out the property
taxes paid to Oxford over a 22-year period.
On February 9, 2000, we announced that the CEC approved plans to construct
the Delta Energy Center in Pittsburg, California. The Delta Energy Center, an
880 megawatt gas-fired power plant located at the Dow Chemical facility, is the
first power plant that will be developed, owned and operated under a joint
venture with Bechtel Enterprises, and will provide power to Pittsburg,
California and the greater San Francisco Bay area.
On February 22, 2000, we announced plans to build, own and operate the Lone
Oak Energy Center, a 800 megawatt gas-fired cogeneration facility located in
Lowndes County, Mississippi. We anticipate that construction will commence in
early 2001 and that commercial operation of the facility will commence in early
2003.
On February 24, 2000, we announced plans to build, own and operate the
Hillabee Energy Center, a 700 megawatt gas-fired cogeneration facility located
in Tallapoosa County, Alabama. We anticipate that construction will commence in
early 2001 and that commercial operation of the facility will commence in early
2003.
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power
plants and steam fields, for which results are consolidated in our statements of
operations. The information set forth under Power Plants consists of the results
for the West Ford Flat Power Plant, Bear Canyon Power Plant, Greenleaf 1 & 2
Power Plants, Watsonville Power Plant, King City Power Plant, Gilroy Power
Plant, the Bethpage Power Plant since its acquisition on February 5, 1998, the
Texas City and Clear Lake Power Plants since their acquisition on March 31,
1998, the Pasadena Power Plant since it began commercial operation on July 7,
1998, the Sonoma Power Plant since its acquisition on July 17, 1998, the
Pittsburg Power Plant since its acquisition on July 21, 1998, the 12 Sonoma
County and 2 Lake County power plants purchased from PG&E on May 7, 1999, the
acquisition of an additional 50% interest in the Aidlin Power Plant on August
31, 1999, the Calistoga Power Plant since its acquisition on October 21, 1999
and five facilities (Newark, Pryor, Parlin, and Morris Power Plants and
Philadelphia Water Project) that we acquired with our purchase of 80% of CGCA on
December 17, 1999. The information set forth under Steam Fields consists of the
results for the Thermal Power Company Steam Fields prior to the acquisition of
Unocal Corporation's interest in the Thermal Power Company steam fields on March
19, 1999 and of the PG&E power plants on May 7, 1999.
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------
1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- -----------
(DOLLARS IN THOUSANDS)
POWER PLANTS:
Electricity revenue(1):
Energy............................ $ 54,886 $ 93,851 $ 110,879 $ 252,178 $ 555,779
Capacity.......................... $ 30,485 $ 65,064 $ 84,296 $ 193,535 $ 183,696
Megawatt hours produced........... 1,033,566 1,985,404 2,158,008 9,864,080 14,802,709
Average energy price per megawatt
hour(2)........................ $ 53.10 $ 47.27 $ 51.38 $ 25.57 $ 37.55
STEAM FIELDS:
Steam revenue(3):................. $ 39,669 $ 40,549 $ 42,102 $ 36,130 $ 20,850
Megawatt hours produced........... 2,415,059 2,528,874 2,641,422 2,323,623 1,192,722
Average price per megawatt hour... $ 16.43 $ 16.03 $ 15.94 $ 15.55 $ 17.48
- ---------------
(1) Electricity revenue is composed of fixed capacity payments, which are not
related to production, and variable energy payments, which are related to
production. For the year ended December 31, 1999, Capacity revenues include,
besides traditional capacity payments, other revenues such as Reliability
Must Run and Ancillary Service revenues.
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(2) Represents variable energy revenue divided by the megawatt-hours produced.
The significant increase in capacity revenue and the accompanying decline in
average energy price per megawatt-hour since 1994 primarily reflects the
increase in our megawatt hour production as a result of additional gas-fired
power plants.
(3) The decline in steam revenue between 1999 and 1997 reflects the acquisition
and consolidation of the Sonoma Power Plant and the related steam fields.
Due to the consolidation of our ownership of the steamfields and the power
plants purchased from PG&E on May 7, 1999, we have ceased recognizing
revenue for the Steam Fields after May 7, 1999.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Revenue -- Total revenue increased 52% to $847.7 million in 1999 compared
to $555.9 million in 1998, primarily due to the impact of recognizing a full
year's income from various assets that were acquired in 1998 and of recognizing
a partial year's income from various assets that were acquired in 1999, as
described below.
Electricity and steam sales revenue increased 50% to $760.3 million in
1999 compared to $507.9 million in 1998. Geothermal revenues at the Geysers
accounted for $125.8 million, or roughly half, of the total increase of
$252.4 million. This was primarily due to the purchase of 14 geothermal
power plants from PG&E on May 7, 1999 and, to a much lesser extent, due to
the purchases of: (1) an additional 50% stake in the Aidlin Power Plant in
August, 1999 after which we consolidated the plant into our financial
results; and (2) the Calistoga Power Plant on October 19, 1999. In 1999 our
geothermal steamfield sales of steam declined by $3.0 million compared to
1998, due to consolidation of steamfield and power plant operations at the
Geysers under Calpine ownership in May 1999, after which we stopped
recording revenues from geothermal steamfield sales to third parties.
The remainder of the increase in electricity and steam sales revenue
is attributable to our gas fired power plants. In California, the Gilroy
Power Plant increased its revenue in 1999 by $27.9 million over 1998 by
both (1) doubling its production, mostly as a result of the expiration of
PG&E's curtailment rights on December 31, 1998 and (2) restructuring its
power purchase agreement with PG&E, effective as of September 1, 1999.
Also, the Pittsburg Power Plant in California increased its revenue by
$12.6 million in 1999 versus 1998. We acquired the project on July 21, 1998
and did not have a full year of operations in 1998. In Texas, the Texas
City and Clear Lake Power Plants, which were consolidated into our
financial statements following the acquisition of the remaining 50%
interest of Texas Cogeneration Company ("TCC") on March 31, 1998, benefited
by a full year of operations in 1999 versus only nine months on a
consolidated basis in 1998, and together they recorded an additional $39.0
million of revenue in 1999 versus in 1998. And finally the Pasadena Power
Plant, which commenced operation in July 1998, had $43.6 million of
additional revenue in 1999 compared to 1998 due to a full year of
operations in 1999.
Service contract revenue increased 117% to $43.8 million in 1999
compared to $20.2 million in 1998. The $23.5 million increase was primarily
due to an increase in recorded sales of purchased power to third parties
and to an increase in sales of purchased gas to third parties.
Income from unconsolidated investments in power projects increased 45%
to $36.6 million in 1999 compared to $25.2 million in 1998. The increase of
$11.4 million is primarily attributable to an increase of equity income
from the Sumas Power Plant. In 1999 we recorded $21.8 million versus $11.7
million in 1998, an increase of $10.1 million. Additionally, as a group,
our equity income projects on the East Coast, Lockport Power Plant, Stony
Brook Power Plant, Kennedy International Airport Power Plant, Gordonsville
Power Plant, Auburndale Power Plant, and Bayonne Power Plant, increased by
$4.1 million. This was offset by a $2.9 million reduction in equity income
attributable to our Clear Lake and Texas City Power Plants, which were
unconsolidated investments for part of 1998 until our purchase of the
remaining 50% interest in TCC on March 31, 1998.
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Interest income on loans to power projects decreased 54% to $1.2
million in 1999 compared to $2.6 million in 1998. In 1999 we no longer
received interest income associated with the TCC investment following our
purchase of the remaining 50% interest in TCC on March 31, 1998. In 1999,
we recorded $1.2 million of income from our 20% investment in Sheridan
California Energy, Inc. We no longer recognize this revenue following our
purchase of the remaining 80% interest through the acquisition of Sheridan
Energy, the parent of Sheridan California Energy, Inc., on October 1, 1999.
Other revenue was $5.8 million in 1999 compared to $0 in 1998. In 1999
we recorded $5.3 million of oil and gas revenue following our acquisition
of Sheridan Energy on October 1, 1999. Additionally, we recorded $0.5
million of equipment sales and service revenue from a group of English
subsidiaries of CGCA, which we acquired 80% on December 17, 1999.
Cost of revenue -- Cost of revenue increased to $557.5 million in 1999
compared to $375.3 million in 1998, an increase of $182.2 million, or 49%.
Fuel expense increased by $87.1 million to $268.7 million in 1999
compared to $181.6 million in 1998 due primarily to: (1) a full year of
consolidated operations in 1999 for the Clear Lake and Texas City Power
Plants versus only nine months in 1998; (2) a full year of operations in
1999 versus a partial year in 1998 for the Pasadena Power Plant, which
commenced commercial operations in July, 1998; (3) a full year of
operations in 1999 versus a partial year in 1998 for the Pittsburg Power
Plant, which we acquired on July 21, 1998; and (4) higher production in
1999 compared to 1998, and therefore higher fuel expense, at our Gilroy and
King City Power Plants due to the expiration of PG&E's curtailment rights
on December 31, 1998 and April 28, 1999 respectively.
Plant operating expense increased by $43.8 million to $118.3 million
in 1999 compared to $74.5 million in 1998 due primarily to higher
geothermal plant operating expense in 1999 following our purchase of 14
geothermal power plants from PG&E on May 7, 1999 and our purchase of
geothermal steam field assets from Unocal Corporation on March 19, 1999.
Depreciation expense increased by $8.8 million to $82.8 million in
1999 compared to $74.0 million in 1998 primarily due to a full year of
operations in 1999 versus partial years in 1998 for the Texas City, Clear
Lake and Pasadena Power Plants, as noted above, and also due to our
purchase of Sheridan Energy on October 1, 1999.
Operating lease expense increased by $16.5 million to $33.6 million in
1999 compared to $17.1 million in 1998. $10.8 million of the increase is
due to the sale-leaseback in May 1999 of the 14 geothermal power plants
acquired from PG&E in May 1999 and the Sonoma Power Plant, which we
acquired in July 1998. We later added the Calistoga Power Plant, which we
acquired in October 1999, to that lease. The remainder of the increase is
primarily due to recording a full year of expense in 1999 versus a partial
year in 1998 for the Greenleaf 1 and 2 Power Plants, which were leased
commencing in August 1998.
Production royalty expense increased by $ 3.1 million to $13.8 million
in 1999 compared to $10.7 million in 1998 due to our purchase of geothermal
steam field assets from Unocal Corporation on March 19, 1999.
Service contract expense increased by $ 22.8 million to $40.2 million
in 1999 compared to $17.4 million in 1998 due to higher recorded purchases
of electricity and gas that were sold to third parties.
Gross profit -- Gross profit increased by $109.7 million, or 61%, to $290.3
million in 1999 compared to $180.6 million in 1998 due primarily to the purchase
of geothermal steam field assets from Unocal Corporation on March 19, 1999 and
14 geothermal power plants from PG&E on May 7, 1999. Overall, the consolidated
geothermal operations at the Geysers increased gross profit in 1999 by $64.6
million compared to 1998. Also, contributing $12.4 million to the increase is
the Gilroy Power Plant, which benefited from the contract restructuring with
PG&E. The Pasadena Power Plant, which benefited from a full year of operations
in 1999, contributed an increase of $17.0 million, and we also realized $11.4
million in additional equity
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income from unconsolidated projects in 1999 compared to 1998 owing mostly to
increased distributions from the Sumas Power Plant.
Project development expenses -- Project development expenses increased by
$3.5 million, or 49%, in 1999 to $10.7 million compared to $7.2 million in 1998
due to the overall heavier pace in development activities as described in
Business -- Project Development and Acquisitions.
General and administrative expenses -- In 1999 general and administrative
expenses were $53.0 million compared to $26.8 million in 1998. The increase of
98% or $26.2 million is largely attributable to the establishment of regional
offices in Pleasanton, CA, and Boston, MA, the build-up of our Houston, TX
regional office and the establishment of our construction management office in
Sacramento, CA. In addition to higher headcount and salaries associated with our
substantial growth, we incurred larger employee bonus expense owing to the
record year we experienced in 1999. The increased general and administrative
investment in 1999 reflects, in part, increased expenses designed to support our
growth in 2000 and beyond.
Interest expense -- Interest expense before capitalization of interest was
$138.5 million in 1999 compared to $93.7 million in 1998, an increase of
$44.8 -- million due to higher debt balances in 1999 (total debt increased by
$982.3 million due primarily to our public offering of $600.0 million of senior
notes on March 29, 1999). However, actual reported interest expense increased by
a much smaller $4.4 million, or 5%, in 1999 compared to 1998 because we
capitalized substantially more interest in 1999 compared to 1998 due to our
heavy power plant construction program. By the fourth quarter of 1999, we had 9
construction projects underway. We capitalized $47.3 million of interest expense
in 1999 compared to $7.0 million in 1998, which is an increase of $40.3 million
in capitalized interest expense.
Total interest expense on senior notes increased by $ 46.1 million to
$121.8 million in 1999 compared to $75.7 million in 1998. Although the average
interest rate on the Senior Notes decreased by 0.4% in 1999 compared to 1998,
interest expense increased because of the additional $600.0 million of Senior
Notes issued in March 1999. The proceeds of the senior notes issued in March of
1999 were used partially to retire $120.6 million of debt related to the Gilroy
Power Plant, and interest expense on the Gilroy debt decreased by $6.7 million
in 1999 compared to 1998. Additionally, we increased debt by $97.8 million with
the acquisition of Sheridan Energy on October 1, 1999 and due to Sheridan's
purchase of certain gas reserves from Vintage Petroleum, Inc. on December 31,
1999. Interest on Sheridan debt was $1.3 million in 1999. We also increased debt
by $241.0 million by acquiring CGCA on December 17, 1999. Interest expense from
CGCA debt in 1999 following the acquisition was $491,000.
Interest income -- In 1999, interest income was $24.1 million compared to
$12.3 million in 1998. The increase of 96% or $11.8 million is attributable to
higher average cash balances in 1999 owing to the public offerings of senior
notes and common stock in March, 1999, and due to the public offerings of common
stock and HIGH TIDES in October 1999.
Other income, net -- In 1999, other income was $1.3 million compared to
$1.1 million in 1998. In 1999 we recorded $655,000 of income associated with an
investment in Cheng Power Systems, Inc. and $324,000 from the sale of excess
nitrous oxide "NOX" credits by the Bethpage Power Plant.
Distributions on Trust Preferred Securities -- In October 1999 we completed
a public offering by a subsidiary trust of 5,520,000 HIGH TIDES. The accrued
distributions through December 31, 1999 were $2.6 million.
Provision for income taxes -- The effective income tax rate was
approximately 39% in 1999 compared to 37% in 1998. The rate increase in 1999 is
primarily attributable to a higher average state tax rate based on the mix of
states in which we worked. In 1999 our provision for federal and state income
taxes totaled $62.0 million versus $27.1 million in 1998, an increase of $34.9
million, which is due primarily to higher taxable income in 1999.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Revenue -- Total revenue increased 101% to $555.9 million in 1998 compared
to $276.3 million in 1997.
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Electricity and steam sales revenue increased 114% to $507.9 million
in 1998 compared to $237.3 million in 1997. The increase is primarily
attributable to the acquisition of the remaining interest in the Texas
City, Clear Lake and Bethpage Power Plants and the acquisition of the
Pittsburg Power Plant. These power plants accounted for $245.2 million in
additional electricity revenues in 1998. We benefited from the startup of
our power plant in Pasadena, Texas, which became operational in July 1998.
This power plant contributed $30.5 million in revenue during 1998. During
1998, we produced 9,864,080 megawatt hours, which was 7,706,072 megawatt
hours higher than the same period in 1997, as a result of the factors
described above. We recently announced three acquisitions, which we expect
to complete during 1999, upon government approval. These acquisitions when
completed will eliminate steam revenue for The Geysers, reflecting the
consolidation of the acquired power plants and related steam fields.
Service contract revenue increased 98% to $20.2 million in 1998
compared to $10.2 million in 1997. The $10.0 million increase was primarily
due to $3.3 million for fuel management fees, and $7.5 million for third
party excess gas sales.
Income from unconsolidated investments in power projects increased 59%
to $25.2 million in 1998 compared to $15.8 million in 1997. The increase of
$9.4 million is primarily attributable to our investments in the Lockport,
Stony Brook and Kennedy International Airport Power Plants, which
contributed $5.2 million of equity income during 1998, as well as $2.5
million of equity income from the Bayonne Power Plant. For the year ended
December 31, 1998, we also recorded $11.7 million of equity income from the
Sumas Power Plant compared to $8.5 million for the same period in 1997.
These increases in equity income were partially offset by a $1.1 million
decrease from the Auburndale Power Plant.
Interest income on loans to power projects decreased 80% to $2.6
million in 1998 compared to $13.0 million in 1997. This decrease was
attributable to the acquisition of the remaining 50% interest in TCC on
March 31, 1998 and the sale of a note receivable in December 1997.
Cost of revenue -- Cost of revenue increased to $375.3 million in 1998
compared to $153.3 million in 1997. The increase of $222.0 million in 1998 was
primarily attributable to increased plant operating, fuel and depreciation
expenses as a result of the acquisition of the remaining interest in the Texas
City, Clear Lake and Bethpage Power Plants, the acquisition of the Pittsburg
Power Plant and the startup of the Pasadena Power Plant. Additionally, service
contract expenses increased $8.8 million for the year ended December 31, 1998,
of which $6.6 million was related to costs associated with the sale of third
party excess gas and a $1.8 million increase for fuel management contracts.
General and administrative expenses -- General and administrative expenses
increased 46% to $26.8 million in 1998 compared to $18.3 million in 1997. The
increase was attributable to the continued growth in personnel and overhead
costs necessary to support the overall growth in our operations.
Interest expense -- Interest expense increased 41% to $86.7 million in 1998
compared to $61.5 million in 1997. The increase was primarily attributable to
interest expense of $35.0 million related to the senior notes issued in 1998 and
1997. This increase was partially offset by $3.5 million for the repayment of
non-recourse project financing for our Geysers facilities, $2.9 million for
reduction of the TCC debt, $2.0 million for reduction of the indebtedness of the
Greenleaf 1 & 2 Power Plants and $1.7 million of interest capitalized on the
development and construction of power projects.
Interest income -- Interest income decreased 14% to $12.3 million in 1998
compared to $14.3 million in 1997. The decrease was primarily attributable to
less interest earned on restricted cash in 1998.
Other income, net -- Other income decreased 66% to $1.1 million in 1998
compared to $3.2 million in 1997. The decrease was primarily attributable to gas
refunds received in 1997.
Provision for income taxes -- The effective income tax rate was
approximately 37% in 1998 compared to 35% in 1997. The effective rates were
lower than the statutory rate (federal and state) primarily due to depletion in
excess of tax basis benefits at our geothermal facilities, and a decrease in the
California tax liability due to our expansion into states other than California.
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LIQUIDITY AND CAPITAL RESOURCES
To date, we have obtained cash from our operations, borrowings under our
credit facilities and other working capital lines, sale of debt and equity, and
proceeds from non-recourse project financing. We utilized this cash to fund our
operations, service debt obligations, fund the acquisition, development and
construction of power generation facilities, finance capital expenditures and
meet our other cash and liquidity needs. The following table summarizes our cash
flow activities for the periods indicated:
YEARS ENDED DECEMBER 31,
-------------------------------------
1999 1998 1997
----------- --------- ---------
(IN THOUSANDS)
Cash flows from:
Operating activities................. $ 264,083 $ 164,579 $ 106,553
Investing activities................. (1,490,417) (400,003) (400,250)
Financing activities................. 1,479,173 283,443 246,240
----------- --------- ---------
Total........................ $ 252,839 $ 48,019 $ (47,457)
=========== ========= =========
Operating activities for 1999 provided $264.1 million, a 60% increase from
1998, consisting of approximately $87.2 million of depreciation and
amortization, $95.1 million of net income, $43.3 million of distributions from
unconsolidated investments in power projects, $47.9 million of deferred income
taxes, an $74.9 million net increase in operating liabilities and a loss on sale
of assets of $1.1 million. This was partially offset by $48.9 million net
increase in operating assets and $36.6 million of income from unconsolidated
investments. The increase in cash provided from operating activities in 1999 is
primarily due to higher net income derived from our acquisition activity in 1998
and 1999.
Investing activities for 1999 used $1.5 billion, primarily due to $929.7
million for construction costs and capital expenditures including gas
turbine-generator costs, $102.2 million for the acquisition of steam fields from
Unocal, $67.9 million for the acquisition of CNGC, $71.5 million for the
purchase of gas reserves from Vintage Petroleum Inc., $7.2 million for the
acquisition of an additional 50% interest in the Aidlin Power Plant, $77.9
million for the acquisition of the Calistoga Power Plant, $212.7 million for the
acquisition of CGCA, advances to the Lost Pines I Joint Venture of $18.1
million, $30.2 million of capitalized project development costs, $47.3 million
of interest capitalized on construction projects, $8.2 million of additional
loans to principal owners of power plants, offset by $1.9 million of maturities
of collateral securities in connection with the King City Power Plant, the
repayment of $9.5 million of outstanding loans, a $1.2 million decrease in
restricted cash, and $71.2 million from the sale and leaseback transactions of
the Geysers Power Company plants and the Calistoga Power Plant. The increase in
cash used in investing activities in 1999 is primarily due to increased
acquisition activity compared to 1998.
Financing activities for 1999 provided $1.5 billion of cash consisting of
$155.8 million of borrowings primarily for the expansion of the Pasadena Power
Plant, $163.7 million of borrowings of notes payable, $600.0 million of gross
proceeds from an additional senior debt financing received in March 1999, $597.4
million of gross proceeds from public common stock offerings in March and
October of 1999, $276.0 million in gross proceeds from a public offering of a
subsidiary trust of 5,520,000 HIGH TIDES in October 1999, $2.1 million for the
issuance of common stock for our Employee Stock Purchase Plan, $812,000 proceeds
from the exercise of stock options and $1.9 million for the write off of
deferred financing costs in April 1999, partially offset by $129.7 million in
repayment of notes payable, $120.6 million in repayment of non-recourse project
financing for the Gilroy Power Plant in April 1999, $2.8 million of repayments
of other non-recourse project financing, and $65.4 million of financing costs.
The increase in cash provided from financing activities in 1999 is primarily due
to the debt and equity offerings issued during 1999, as well as the HIGH TIDES
issued by a subsidiary trust in 1999.
At December 31, 1999, cash and cash equivalents were $349.4 million and
working capital was $251.1 million. For 1999, cash and cash equivalents
increased by $252.8 million and working capital increased by $164.2 million as
compared to December 31, 1998. The increases in cash and cash equivalents and
working
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capital in 1999 is primarily attributable to the equity offering issued in
October 1999, as well as the HIGH TIDES issued by a subsidiary trust in October
1999.
As a developer, owner and operator of power generation facilities, we are
required to make long-term commitments and investments of substantial capital
for our projects. We historically have financed these capital requirements with
cash from operations, borrowings under our credit facilities, other lines of
credit, construction financing, non-recourse project financing or long-term
debt, and the sale of equity.
We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit, access to the capital markets and working
capital to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements for
the next twelve months.
Credit Facilities (see Note 5 to the Notes to Consolidated Financial
Statements)
At December 31, 1999, we had a $100.0 million revolving credit facility
available with a consortium of commercial lending institutions. We had no
borrowings and $28.8 million of letters of credit outstanding under this credit
facility. Borrowings bear interest at The Bank of Nova Scotia's base rate plus
an applicable margin or at LIBOR plus an applicable margin.
At December 17, 1999, we, through our acquisition of CGCA, assumed a $25.0
million revolving credit facility with MeesPierson Capital Corporation. As of
December 31, 1999, all of the available credit under this facility was
outstanding. Interest is variable based upon, at our option, LIBOR plus a margin
ranging from 1.50% to 1.875% or the prime rate plus a margin ranging from 0.75%
to 1.125%.
At December 31, 1999, we had a credit agreement for $1.0 billion with a
consortium of banks with the lead arranger being The Bank of Nova Scotia and the
lead arranger syndication agent being Credit Suisse First Boston. We had no
borrowings outstanding under this facility. Borrowings under this facility bear
interest, at our option, at the prime commercial lending rate, the Federal Funds
Rate plus 0.50% or LIBOR.
On October 1, 1999, we completed the acquisition of Sheridan Energy, a
natural gas exploration and production company, through a $38.8 million cash
tender offer. Sheridan Energy, at December 31, 1999, maintains a borrowing base
facility of $24.5 million with Bank One, Texas, N.A. As of December 31, 1999,
Sheridan had total borrowings outstanding of $24.3 million with a final maturity
of December 31, 2001. Sheridan may elect to borrow at Bank One's stated rate, or
LIBOR plus 2.5%, or a combination thereof.
In conjunction with the acquisition of certain properties located in
California, Bank One extended a separate borrowing base facility of $74.6
million as of December 31, 1999 to Sheridan California Energy, Inc, a wholly
owned subsidiary of Sheridan Energy. As of December 31, 1999, there was $73.5
million outstanding under the SCEI facility with a final maturity of December
31, 2001.
Project Financing (see Note 6 to the Notes to Consolidated Financial
Statements)
On January 4, 1999, the Company entered into a Credit Agreement with ING
(U.S.) Capital LLC to provide up to $265.0 million of non-recourse project
financing for the construction of the Pasadena Power Plant expansion. As of
December 31, 1999, $154.8 million was outstanding as a construction loan under
the agreement. The outstanding loan bears interest at ING's base rate plus an
applicable margin or at LIBOR plus an applicable margin, and is payable
quarterly.
On December 17, 1999, we acquired CGCA, which owns 100% of the debt of
Morris LLC. On September 15, 1997, Morris entered into a construction and term
loan agreement to provide non-recourse project financing for a major portion of
the Morris Project. The agreement provides $85.6 million of 20-month
construction loan commitments and $5.4 million in letter of credit commitments.
As of December 31, 1999, $85.6 million was outstanding as a construction loan
under the agreement and no amounts were pledged under the letter of credit.
Interest on the construction loan is variable based on, at our option, either
the base rate, as defined in the construction and term loan agreement, or LIBOR
plus 0.75%.
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On December 17, 1999, we acquired CGCA, which owns 100% of the Newark and
Parlin Power Plants. We have $125.3 million outstanding on a 15 year
non-recourse term loan which is a joint and severable liability of Newark and
Parlin. The interest rate on the outstanding principal is variable based on, at
our option, LIBOR plus 1.125% margin or a defined base rate plus 0.375% margin.
Debt and Equity Offerings (see Notes 7, 8 and 9 to the Notes to Consolidated
Financial Statements)
On March 26, 1999, we completed a public offering of 12,000,000 shares of
our common stock at $15.50 per share. The net proceeds from this public offering
were approximately $177.1 million. In April 1999, we sold an additional
1,800,000 shares of common stock at $15.50 per share pursuant to the exercise of
the underwriters' over-allotment option for net proceeds of approximately $26.7
million.
On March 29, 1999, we completed a public offering of $250.0 million of our
7 5/8% Senior Notes Due 2006 and of our $350.0 million 7 3/4% Senior Notes Due
2009. After deducting underwriting discounts and expenses of the offering, the
aggregate net proceeds from the sale of the Senior Notes were approximately
$589.6 million. The Senior Notes Due 2006 bear interest at 7 5/8% per year,
payable semi-annually on April 15 and October 15 each year and mature on April
15, 2006. The Senior Notes Due 2006 are not redeemable prior to maturity. The
Senior Notes Due 2009 bear interest at 7 3/4% per year, payable semi-annually on
April 15 and October 15 each year and mature on April 15, 2009. The Senior Notes
Due 2009 are not redeemable prior to maturity.
The net proceeds from the sale in March 1999 of the common stock, the
Senior Notes Due 2006, and the Senior Notes Due 2009 were used as follows: (i)
$120.6 million to refinance indebtedness relating to the Gilroy Power Plant,
(ii) $77.6 million to repay indebtedness under a bridge facility provided by
Credit Suisse First Boston to finance a portion of the purchase price to acquire
the steam fields that service the Sonoma County power plants, (iii) $50.0
million to repay outstanding borrowings under our revolving credit facility,
(iv) $25.0 million to complete the expansion of the Clear Lake Power Plant, (v)
approximately $400.0 million to finance a portion of power generation facilities
currently under construction and the projects currently under development, and
(vi) the remaining $120.2 million were used for general corporate purposes.
Transaction costs incurred in connection with the Senior Notes offering were
recorded as a deferred charge and are amortized over the respective lives of the
Senior Notes Due 2006 and the Senior Notes Due 2009 using the effective interest
rate method.
In October 1999, we completed a public offering of 8,280,000 shares of our
common stock at $46.31 per share and 5,520,000 1999 5 3/4% HIGH TIDES issued by
a subsidiary trust at $50.00 each, raising $636.7 million of aggregate net
proceeds to Calpine.
The net proceeds from the sale in October 1999 of the common stock and HIGH
TIDES were used to finance power projects under development and construction. In
addition, we used $137.3 million of the net proceeds to complete the acquisition
of 80% of CGCA. The remaining net proceeds will be used for working capital and
general corporate purposes.
Senior Notes
At December 31, 1999, we also had $105.0 million of outstanding 9 1/4%
Senior Notes Due 2004, which mature on February 1, 2004, with interest payable
semi-annually on February 1 and August 1 of each year. In addition, we had
$171.8 million of outstanding 10 1/2% Senior Notes Due 2006, which mature on May
15, 2006, with interest payable semi-annually on May 15 and November 15 of each
year. During 1997, we issued $275.0 million of 8 3/4% Senior Notes Due 2007,
which mature on July 15, 2007, with interest payable semi-annually on January 15
and July 15 of each year. During 1998, we issued $400.0 million of 7 7/8% Senior
Notes Due 2008, which mature on April 1, 2008, with interest payable
semi-annually on April 1 and October 1 of each year.
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OUTLOOK
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power industry, primarily through our active
development and acquisition programs. In pursuing our proven growth strategy, we
utilize our extensive management and technical expertise to implement a fully
integrated approach to the acquisition, development and operation of power
generation facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provide us with a competitive
advantage. The key elements of our strategy are as follows:
- Development of new and expansion of existing power plants. We are
actively pursuing the development of new and expansion of existing highly
efficient, low-cost, gas-fired power plants that replace old and
inefficient generating facilities and meet the demand for new generation.
Our strategy is to develop power plants in strategic geographic locations
that enable us to leverage existing power generation assets and operate
the power plants as integrated electric generation systems. This allows
us to achieve significant operating synergies and efficiencies in fuel
procurement, power marketing and operations and maintenance.
We currently have twelve new projects under construction, representing an
additional 5,935 megawatts of capacity. Of these new projects, we are
expanding our Pasadena facility by 545 megawatts to 785 megawatts and the
Morris facility by 50 megawatts to 167 megawatts. We have ten new power
plants under construction, including the Baytown Power Plant in Texas;
Tiverton Power Plant in Rhode Island; the Rumford Power Plant in Maine;
the Westbrook Power Plant in Maine; the Sutter Power Plant in California;
the Los Medanos Power Plant in California; the South Point Power Plant in
Arizona; the Magic Valley Power Plant in Texas; the Lost Pines I Power
Plant in Texas; and the Aries Power Plant in Missouri. We have also
announced plans to develop twelve additional power generation facilities,
totaling 7,990 megawatts, in California, Mississippi, Connecticut,
Florida, Texas, Alabama, Oregon, Arizona and Pennsylvania.
- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and provide
significant potential for revenue, cash flow and earnings growth, and
that provide the opportunity to enhance the operating efficiencies of the
plants. We have significantly expanded and diversified our project
portfolio through the acquisition of power generation facilities through
the completion of 41 acquisitions to date.
- Enhance the performance and efficiency of existing power projects. We
continually seek to maximize the power generation potential of our
operating assets and minimize our operating and maintenance expenses and
fuel costs. This will become even more significant as our portfolio of
power generation facilities expands to an aggregate of 54 power plants
with an aggregate capacity of approximately 10,208 megawatts, after
completion of our projects currently under construction. We focus on
operating our plants as an integrated system of power generation, which
enables us to minimize costs and maximize operating efficiencies. We
believe that achieving and maintaining a low-cost of production will be
increasingly important to compete effectively in the power generation
industry.
RISK FACTORS
We have substantial indebtedness that we may be unable to service and that
restricts our activities. We have substantial debt that we incurred to finance
the acquisition and development of power generation facilities. As of December
31, 1999, our total consolidated indebtedness was $2.1 billion, our total
consolidated assets were $4.0 billion and our stockholders' equity was $964.6
million. Whether we will be able to meet our debt service obligations and to
repay our outstanding indebtedness will be dependent primarily upon the
performance of our power generation facilities.
This high level of indebtedness has important consequences, including:
- limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, execution of our growth
strategy, or other purposes,
F-16
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- limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt,
- increasing our vulnerability to general adverse economic and industry
conditions, and
- limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.
The operating and financial restrictions and covenants in our existing debt
agreements, including the indentures relating to our $1.6 billion aggregate
principle amount of senior notes, our $1.0 billion revolving credit facility,
and our $100.0 million revolving credit facility, contain restrictive covenants.
Among other things, these restrictions limit or prohibit our ability to:
- incur indebtedness,
- make prepayments of indebtedness in whole or in part,
- pay dividends,
- make investments,
- engage in transactions with affiliates,
- create liens,
- sell assets, and
- acquire facilities or other businesses.
Also, if our management or ownership changes, the indentures governing our
senior notes may require us to make an offer to purchase our senior notes. We
cannot assure you that we will have the financial resources necessary to
purchase our senior notes in this event.
We believe that our cash flow from operations, together with other
available sources of funds, including borrowings under our existing borrowing
arrangements, will be adequate to pay principal and interest on our senior notes
and other debt and to enable us to comply with the terms of our indentures and
other debt agreements. If we are unable to comply with the terms of our
indentures and other debt agreements and fail to generate sufficient cash flow
from operations in the future, we may be required to refinance all or a portion
of our senior notes and other debt or to obtain additional financing. However,
we may be unable to refinance or obtain additional financing because of our high
levels of debt and the debt incurrence restrictions under our indentures and
other debt agreements. If cash flow is insufficient and refinancing or
additional financing is unavailable, we may be forced to default on our senior
notes and other debt obligations. In the event of a default under the terms of
any of our indebtedness, the debt holders may accelerate the maturity of our
obligations, which could cause defaults under our other obligations.
Our ability to repay our debt depends upon the performance of our
subsidiaries. Almost all of our operations are conducted through our
subsidiaries and other affiliates. As a result, we depend almost entirely upon
their earnings and cash flow to service our indebtedness, including our ability
to pay the interest on and principal of our senior notes. The non-recourse
project financing agreements of certain of our subsidiaries and other affiliates
generally restrict their ability to pay dividends, make distributions or
otherwise transfer funds to us prior to the payment of other obligations,
including operating expenses, debt service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation to pay any amounts due on our senior notes, and
do not guarantee the payment of interest on or principal of these notes. The
right of our senior note holders to receive any assets of any of our
subsidiaries or other affiliates upon our liquidation or reorganization will be
subordinated to the claims of any subsidiaries' or other affiliates' creditors
(including trade creditors and holders of debt issued by our subsidiaries or
affiliates). As of December 31, 1999, our subsidiaries had $365.7 million of
non-recourse project financing. We intend to utilize non-recourse project
financing, when appropriate in the future, and this financing will be
effectively senior to our senior notes.
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While the indentures impose limitations on our ability and the ability of
our subsidiaries to incur additional indebtedness, the indentures do not limit
the amount of non-recourse project financing that our subsidiaries may incur to
finance the acquisition and development of new power generation facilities.
We may be unable to secure additional financing in the future. Each power
generation facility that we acquire or develop will require substantial capital
investment. Our ability to arrange financing and the cost of the financing are
dependent upon numerous factors. These factors include:
- general economic and capital market conditions,
- conditions in energy markets,
- regulatory developments,
- credit availability from banks or other lenders,
- investor confidence in the industry and in us,
- the continued success of our current power generation facilities, and
- provisions of tax and securities laws that are conducive to raising
capital.
Financing for new facilities may not be available to us on acceptable terms
in the future. We have financed our existing power generation facilities using a
variety of leveraged financing structures, primarily consisting of senior
unsecured indebtedness, non-recourse project financing and lease obligations. As
of December 31, 1999, we had approximately $2.1 billion of total consolidated
indebtedness, $365.7 million of non-recourse project financing, and $110.8
million of notes payable. Each non-recourse project financing and lease
obligation is structured to be fully paid out of cash flow provided by the
facility or facilities. In the event of a default under a financing agreement
which we do not cure, the lenders or lessors would generally have rights to the
facility and any related assets. In the event of foreclosure after a default, we
might not retain any interest in the facility. While we intend to utilize
non-recourse or lease financing when appropriate, market conditions and other
factors may prevent similar financing for future facilities. We do not believe
the existence of non-recourse or lease financing will significantly affect our
ability to continue to borrow funds in the future in order to finance new
facilities. However, it is possible that we may be unable to obtain the
financing required to develop our power generation facilities on terms
satisfactory to us.
We have from time to time guaranteed certain obligations of our
subsidiaries and other affiliates. Our lenders or lessors may also require us to
guarantee the indebtedness for future facilities. This would render our general
corporate funds vulnerable in the event of a default by the facility or related
subsidiary. Additionally, our indentures may restrict our ability to guarantee
future debt, which could adversely affect our ability to fund new facilities.
Our indentures do not limit the ability of our subsidiaries to incur
non-recourse or lease financing for investment in new facilities.
Revenue under some of our power sales agreements may be reduced
significantly upon their expiration or termination. Most of the electricity we
generate from our existing portfolio is sold under long-term power sales
agreements that expire at various times. When the terms of each of these power
sales agreements expire, it is possible that the price paid to us for the
generation of electricity may be reduced significantly, which would
substantially reduce our revenue under such agreements.
Our power project development and acquisition activities may not be
successful. The development of power generation facilities is subject to
substantial risks. In connection with the development of a power generation
facility, we must generally obtain:
- necessary power generation equipment,
- governmental permits and approvals,
- fuel supply and transportation agreements,
- sufficient equity capital and debt financing,
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- electrical transmission agreements, and
- site agreements and construction contracts.
We may be unsuccessful in accomplishing any of these matters or in doing so
on a timely basis. In addition, project development is subject to various
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although we may attempt to minimize the financial risks
in the development of a project by securing a favorable power sales agreement,
obtaining all required governmental permits and approvals and arranging adequate
financing prior to the commencement of construction, the development of a power
project may require us to expend significant sums for preliminary engineering,
permitting and legal and other expenses before we can determine whether a
project is feasible, economically attractive or financeable. If we were unable
to complete the development of a facility, we would generally not be able to
recover our investment in the project. The process for obtaining initial
environmental, siting and other governmental permits and approvals is
complicated and lengthy, often taking more than one year, and is subject to
significant uncertainties. We cannot assure you that we will be successful in
the development of power generation facilities in the future.
We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, we may be
unable to continue to identify attractive acquisition opportunities at favorable
prices or, to the extent that any opportunities are identified, we may be unable
to complete the acquisitions.
Our projects under construction may not commence operation as
scheduled. The commencement of operation of a newly constructed power generation
facility involves many risks, including:
- start-up problems,
- the breakdown or failure of equipment or processes, and
- performance below expected levels of output or efficiency.
New plants have no operating history and may employ recently developed and
technologically complex equipment. Insurance is maintained to protect against
certain risks, warranties are generally obtained for limited periods relating to
the construction of each project and its equipment in varying degrees, and
contractors and equipment suppliers are obligated to meet certain performance
levels. The insurance, warranties or performance guarantees, however, may not be
adequate to cover lost revenues or increased expenses. As a result, a project
may be unable to fund principal and interest payments under its financing
obligations and may operate at a loss. A default under such a financing
obligation could result in losing our interest in a power generation facility.
In addition, power sales agreements entered into with a utility early in
the development phase of a project may enable the utility to terminate the
agreement, or to retain security posted as liquidated damages, if a project
fails to achieve commercial operation or certain operating levels by specified
dates or fails to make specified payments. In the event a termination right is
exercised, the default provisions in a financing agreement may be triggered
(rendering such debt immediately due and payable). As a result, the project may
be rendered insolvent and we may lose our interest in the project.
Our power generation facilities may not operate as planned. Upon completion
of our projects currently under construction, we will operate 44 of the 54 power
plants in which we will have an interest. The continued operation of power
generation facilities involves many risks, including the breakdown or failure of
power generation equipment, transmission lines, pipelines or other equipment or
processes and performance below expected levels of output or efficiency.
Although from time to time our power generation facilities have experienced
equipment breakdowns or failures, these breakdowns or failures have not had a
significant effect on the operation of the facilities or on our results of
operations. As of December 31, 1999, our gas-fired and geothermal power
generation facilities have operated at an average availability of approximately
95% and 95%, respectively. Although our facilities contain various redundancies
and back-up mechanisms, a breakdown or
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failure may prevent the affected facility from performing under applicable power
sales agreements. In addition, although insurance is maintained to protect
against operating risks, the proceeds of insurance may not be adequate to cover
lost revenues or increased expenses. As a result, we could be unable to service
principal and interest payments under our financing obligations which could
result in losing our interest in the power generation facility.
Our geothermal energy reserves may be inadequate for our operations. The
development and operation of geothermal energy resources are subject to
substantial risks and uncertainties similar to those experienced in the
development of oil and gas resources. The successful exploitation of a
geothermal energy resource ultimately depends upon:
- the heat content of the extractable fluids,
- the geology of the reservoir,
- the total amount of recoverable reserves,
- operating expenses relating to the extraction of fluids,
- price levels relating to the extraction of fluids, and
- capital expenditure requirements relating primarily to the drilling of
new wells.
In connection with each geothermal power plant, we estimate the
productivity of the geothermal resource and the expected decline in
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or an unexpected decline in productivity could lower our results of operations.
Geothermal reservoirs are highly complex. As a result, there exist numerous
uncertainties in determining the extent of the reservoirs and the quantity and
productivity of the steam reserves. Reservoir engineering is an inexact process
of estimating underground accumulations of steam or fluids that cannot be
measured in any precise way, and depends significantly on the quantity and
accuracy of available data. As a result, the estimates of other reservoir
specialists may differ materially from ours. Estimates of reserves are generally
revised over time on the basis of the results of drilling, testing and
production that occur after the original estimate was prepared. While we have
extensive experience in the operation and development of geothermal energy
resources and in preparing such estimates, we cannot assure you that we will be
able to successfully manage the development and operation of our geothermal
reservoirs or that we will accurately estimate the quantity or productivity of
our steam reserves.
We depend on our electricity and thermal energy customers. A majority of
our power generation facilities currently rely on one or more power sales
agreements with one or more utilities or other customers for all or
substantially all of such facility's revenue. In addition, sales of electricity
to two utility customers during 1999, PG&E and Texas Utilities Electric Company,
comprised approximately 47% of our total revenue that year. The loss of any one
power sales agreement with any of these customers could have a negative effect
on our results of operations. In addition, any material failure by any customer
to fulfill its obligations under a power sales agreement could have a negative
effect on the cash flow available to us and on our results of operations.
We are subject to complex government regulation which could adversely
affect our operations. Our activities are subject to complex and stringent
energy, environmental and other governmental laws and regulations. The
construction and operation of power generation facilities require numerous
permits, approvals and certificates from appropriate federal, state and local
governmental agencies, as well as compliance with environmental protection
legislation and other regulations. While we believe that we have obtained the
requisite approvals for our existing operations and that our business is
operated in accordance with applicable laws, we remain subject to a varied and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. Existing laws and regulations may be revised or
new laws and regulations may become applicable to us that may have a negative
effect on our business and results of
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operations. We may be unable to obtain all necessary licenses, permits,
approvals and certificates for proposed projects, and completed facilities may
not comply with all applicable permit conditions, statutes or regulations. In
addition, regulatory compliance for the construction of new facilities is a
costly and time-consuming process. Intricate and changing environmental and
other regulatory requirements may necessitate substantial expenditures to obtain
permits. If a project is unable to function as planned due to changing
requirements or local opposition, it may create expensive delays or significant
loss of value in a project.
Our operations are potentially subject to the provisions of various energy
laws and regulations, including the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1935, as
amended ("PUHCA"), and state and local regulations. PUHCA provides for the
extensive regulation of public utility holding companies and their subsidiaries.
PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and
owners of QFs certain exemptions from certain federal and state regulations,
including rate and financial regulations.
Under present federal law, we are not subject to regulation as a holding
company under PUHCA, and will not be subject to such regulation as long as the
plants in which we have an interest (1) qualify as QFs, (2) are subject to
another exemption or waiver or (3) qualify as exempt wholesale generators
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by an electric utility company or electric
utility holding company. In addition, a QF that is a cogeneration facility, such
as the plants in which we currently have interests, must produce electricity as
well as thermal energy for use in an industrial or commercial process in
specified minimum proportions. The QF also must meet certain minimum energy
efficiency standards. Generally, any geothermal power facility which produces up
to 80 megawatts of electricity and meets PURPA ownership requirements is
considered a QF.
If any of the plants in which we have an interest lose their QF status or
if amendments to PURPA are enacted that substantially reduce the benefits
currently afforded QFs, we could become a public utility holding company, which
could subject us to significant federal, state and local regulation, including
rate regulation. If we become a holding company, which could be deemed to occur
prospectively or retroactively to the date that any of our plants loses its QF
status, all our other power plants could lose QF status because, under FERC
regulations, a QF cannot be owned by an electric utility or electric utility
holding company. In addition, a loss of QF status could, depending on the
particular power purchase agreement, allow the power purchaser to cease taking
and paying for electricity or to seek refunds of past amounts paid and thus
could cause the loss of some or all contract revenues or otherwise impair the
value of a project. If a power purchaser were to cease taking and paying for
electricity or seek to obtain refunds of past amounts paid, there can be no
assurance that the costs incurred in connection with the project could be
recovered through sales to other purchasers. Such events could adversely affect
our ability to service our indebtedness, including our senior notes. See
"Business -- Government Regulation -- Federal Energy Regulation -- Federal Power
Act Regulation."
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at prices based on avoided costs of energy. We do not know whether this
legislation will be passed or, if passed, what form it may take. We cannot
provide assurance that any legislation passed would not adversely affect our
existing domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
In particular, the state of California has restructured its electric industry by
providing for a phased-in competitive power generation industry, with a power
pool and an independent system operator, and for direct access to generation for
all power purchasers outside the power exchange under certain circumstances.
Although existing QF power sales contracts are to be honored under such
restructuring, and all of our California operating projects are QFs, until the
new system is fully implemented, it is impossible to predict what impact, if
any, it may have on the operations of those projects.
We may be unable to obtain an adequate supply of natural gas in the
future. To date, our fuel acquisition strategy has included various combinations
of our own gas reserves, gas prepayment contracts and short-, medium- and
long-term supply contracts. In our gas supply arrangements, we attempt to match
the
F-21
54
fuel cost with the fuel component included in the facility's power sales
agreements in order to minimize a project's exposure to fuel price risk. We
believe that there will be adequate supplies of natural gas available at
reasonable prices for each of our facilities when current gas supply agreements
expire. However, gas supplies may not be available for the full term of the
facilities' power sales agreements, and gas prices may increase significantly.
If gas is not available, or if gas prices increase above the fuel component of
the facilities' power sales agreements, there could be a negative impact on our
results of operations.
Competition could adversely affect our performance. The power generation
industry is characterized by intense competition. We encounter competition from
utilities, industrial companies and other power producers. In recent years,
there has been increasing competition in an effort to obtain power sales
agreements. This competition has contributed to a reduction in electricity
prices. In addition, many states have implemented or are considering regulatory
initiatives designed to increase competition in the domestic power industry.
This competition has put pressure on electric utilities to lower their costs,
including the cost of purchased electricity.
Our international investments may face uncertainties. We have one
investment in geothermal steam fields located in Mexico and may pursue
additional international investments. International investments are subject to
unique risks and uncertainties relating to the political, social and economic
structures of the countries in which we invest. Risks specifically related to
investments in non-United States projects may include:
- risks of fluctuations in currency valuation,
- currency inconvertibility,
- expropriation and confiscatory taxation,
- increased regulation, and
- approval requirements and governmental policies limiting returns to
foreign investors.
We depend on our senior management. Our success is largely dependent on the
skills, experience and efforts of our senior management. The loss of the
services of one or more members of our senior management could have a negative
effect on our business, financial results and future growth.
Seismic disturbances could damage our projects. Areas where we operate and
are developing many of our geothermal and gas-fired projects are subject to
frequent low-level seismic disturbances. More significant seismic disturbances
are possible. Our existing power generation facilities are built to withstand
relatively significant levels of seismic disturbances, and we believe we
maintain adequate insurance protection. However, earthquake, property damage or
business interruption insurance may be inadequate to cover all potential losses
sustained in the event of serious seismic disturbances. Additionally, insurance
may not continue to be available to us on commercially reasonable terms.
Our results are subject to quarterly and seasonal fluctuations. Our
quarterly operating results have fluctuated in the past and may continue to do
so in the future as a result of a number of factors, including:
- the timing and size of acquisitions,
- the completion of development projects, and
- variations in levels of production.
Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal.
F-22
55
The price of our common stock is volatile. The market price for our common
stock has been volatile in the past, and several factors could cause the price
to fluctuate substantially in the future. These factors include:
- announcements of developments related to our business,
- fluctuations in our results of operations,
- sales of substantial amounts of our securities into the marketplace,
- general conditions in our industry or the worldwide economy,
- an outbreak of war or hostilities,
- a shortfall in revenues or earnings compared to securities analysts'
expectations,
- changes in analysts' recommendations or projections, and
- announcements of new acquisitions or development projects by us.
The market price of our common stock may fluctuate significantly in the
future, and these fluctuations may be unrelated to our performance. General
market price declines or market volatility in the future could adversely affect
the price of our common stock, and the current market price may not be
indicative of future market prices.
YEAR 2000 COMPLIANCE
The "Year 2000 problem" refers to the fact that some computer hardware,
software and embedded systems were designed to read and store dates using only
the last two digits of the year. The problem is further complicated by the fact
that year 2000 is a leap year and computer systems may fail to recognize it as
such.
We have coordinated our efforts to address the Year 2000 problem through a
Year 2000 Project Team comprised of representatives from each business unit and
our Year 2000 Project Office. The Year 2000 Project Office has been charged with
addressing additional Year 2000 related issues including, but not limited to,
business continuation and other contingency planning.
In addition, we have been working with the Electric Power Research
Institute, a consortium of power companies, including investor-owned utilities,
to coordinate vendor contacts and product evaluation. Because many embedded
systems are similar across utilities, we believe that this concerted effort
helped to reduce total time expended in this area and helped to ensure that our
efforts were consistent with the efforts and practices of other power companies
and utilities.
As of February 4, 2000, we are not aware of any Year 2000 problem in any of
our critical corporate applications, non-information technology/embedded
systems, end-user computing systems or business partners' and vendors' systems.
In addition, we have not received any notification from any of our critical
business partners or vendors of any Year 2000-related disruption in their
business. However, the success to date of our Year 2000 efforts and the efforts
of our critical third party vendors or business partners cannot guarantee that
there will not be a material adverse effect on our business should a Year 2000
problem manifest or become apparent in the future.
Costs. The costs of expected modifications were estimated at approximately
$1.7 million, which were charged to expense as incurred. For the year ended
December 31, 1999, approximately $529,000 was charged to expense. Any remaining
costs to be incurred in 2000 will not be material, and will be funded through
operating cash flow.
Risks. Although we have not experienced and do not foresee having a Year
2000 problem, if our systems encounter unforeseen Year 2000 problems, or if one
or more of our significant third party business partners or vendors is unable to
provide services due to a Year 2000 problem, we could experience a disruption of
operations resulting in increased operating costs, loss of revenues and other
adverse effects, but we do not
F-23
56
expect any of these circumstances will have a material adverse effect on our
financial position or results of operations.
FINANCIAL MARKET RISKS
From time to time, we use interest rate swap agreements to mitigate our
exposure to interest rate fluctuations. We do not use derivative financial
instruments for speculative or trading purposes. The following table summarizes
the fair market value of our existing interest rate swap agreements as of
December 31, 1999 (in thousands):
NOTIONAL WEIGHTED
PRINCIPAL AVERAGE FAIR
MATURITY DATE AMOUNT INTEREST RATE MARKET VALUE
------------- --------- ------------- ------------
2000..................................... $ 22,900 8.2% $ (195)
2001..................................... 20,000 5.5% 225
2009..................................... 65,000 6.1% 3,725
2011..................................... 63,860 6.9% 202
2013..................................... 73,095 7.2% (461)
2014..................................... 76,738 6.7% 1,235
-------- --- ------
Total............................. $321,593 6.8% $4,731
======== === ======
Short-term investments. As of December 31, 1999, we have short-term
investments of $230.7 million. These short-term investments consist of highly
liquid investments with maturities less than three months. These investments are
subject to interest rate risk and will increase in value if market interest
rates increase. We have the ability to hold these investments to maturity, and
as a result, we would not expect the value of these investments to be affected
to any significant degree by the effect of a sudden change in market interest
rates. Declines in interest rates over time will reduce our interest income.
Outstanding debt. As of December 31, 1999, we have outstanding debt of
approximately $2.1 billion primarily made up of $1.6 billion of senior notes,
$365.7 million of non-recourse project financing, $122.8 million in borrowings
under lines of credit, and $13.4 million of notes payable. As of December 31,
1999, our non-recourse project financing had a floating interest rate of 6.11%.
Our outstanding long-term Senior Notes as of December 31, 1999 are as follows
(in thousands):
CARRYING FAIR
MATURITY DATE AMOUNT INTEREST RATE MARKET VALUE
------------- ---------- ------------- ------------
2004................................... $ 105,000 9 1/4% $ 106,050
2006................................... 171,750 10 1/2% 180,939
2006................................... 250,000 7 5/8% 238,050
2007................................... 275,000 8 3/4% 275,963
2008................................... 400,000 7 7/8% 384,600
2009................................... 350,000 7 3/4% 320,950
---------- ----------
Total........................... $1,551,750 $1,506,552
========== ==========
Gas price fluctuations. We enter into derivative commodity instruments to
hedge our exposure to the impact of price fluctuations on gas purchases. Such
instruments include regulated natural gas contracts and over-the-counter swaps
and basis hedges with major energy derivative product specialists. All hedge
transactions are subject to our risk management policy which does not permit
speculative positions. These transactions are accounted for under the hedge
method of accounting. Cash flows from derivative instruments are recognized as
incurred through changes in working capital.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In June 1999, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 137, "Accounting for Derivative
Instruments and Hedging Activities -- Deferral of
F-24
57
the Effective Date of FASB Statement No. 133 -- an Amendment of FASB Statement
No. 133". The Statement amends SFAS No. 133 to defer its effective date to all
fiscal quarters of all fiscal years beginning after June 15, 2000. We have not
yet completed our analysis of the impact of adopting SFAS No. 133 on the
financial statements and have not determined the timing of or method of the
adoption of SFAS No. 133. However, the Statement could increase the volatility
of our earnings.
F-25
58
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors
and Stockholders of Calpine Corporation:
We have audited the accompanying consolidated balance sheets of Calpine
Corporation (a Delaware corporation) and subsidiaries as of December 31, 1999
and 1998, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1999. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Calpine Corporation and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
January 31, 2000
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59
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(IN THOUSANDS)
ASSETS
1999 1998
---------- ----------
Current assets:
Cash and cash equivalents................................. $ 349,371 $ 96,532
Accounts receivable, net of allowance of $3,343 and
$238................................................... 127,485 79,743
Inventories............................................... 16,417 14,194
Other current assets...................................... 33,135 19,034
---------- ----------
Total current assets.............................. 526,408 209,503
---------- ----------
Property, plant and equipment, net.......................... 2,866,447 1,094,303
Investments in power projects............................... 284,834 221,509
Project development costs................................... 24,018 17,001
Notes receivable............................................ 23,548 10,899
Restricted cash............................................. 43,615 14,454
Deferred financing costs.................................... 54,215 22,789
Other assets................................................ 168,521 138,488
---------- ----------
Total assets...................................... $3,991,606 $1,728,946
========== ==========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Borrowings under line of credit, current portion.......... $ 35,832 $ --
Non-recourse project financing, current portion........... 8,603 5,450
Notes payable, current portion............................ 3,035 --
Accounts payable.......................................... 84,353 53,190
Income taxes payable...................................... 8,835 --
Accrued payroll and related expenses...................... 24,345 9,588
Accrued interest payable.................................. 37,058 25,600
Other current liabilities................................. 73,250 28,751
---------- ----------
Total current liabilities......................... 275,311 122,579
---------- ----------
Borrowings under line of credit, net of current portion..... 86,918 --
Non-recourse project financing, net of current portion...... 357,137 114,190
Senior notes................................................ 1,551,750 951,750
Notes payable, net of current............................... 10,385 --
Deferred income taxes, net.................................. 291,458 159,788
Deferred lease incentive.................................... 64,245 67,814
Other liabilities........................................... 57,352 25,859
---------- ----------
Total liabilities................................. 2,694,556 1,441,980
---------- ----------
Commitments and contingencies (see Note 15).................
Company-obligated mandatorily redeemable convertible
preferred securities of a subsidiary trust................ 270,713 --
Minority interests.......................................... 61,705 --
---------- ----------
Stockholders' equity:
Preferred stock $0.001 par value per share; authorized
10,000,000 shares; none issued and outstanding in 1999
and 1998............................................... -- --
Common stock, $0.001 par value per share; authorized
100,000,000 shares; issued and outstanding 63,053,920
shares in 1999 and 40,323,162 shares in 1998........... 63 40
Additional paid-in capital................................ 751,404 168,854
Retained earnings......................................... 213,165 118,072
---------- ----------
Total stockholders' equity........................ 964,632 286,966
---------- ----------
Total liabilities and stockholders' equity........ $3,991,606 $1,728,946
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-27
60
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1999 1998 1997
-------- -------- --------
Revenue:
Electricity and steam sales.............................. $760,325 $507,897 $237,277
Service contract revenue................................. 43,773 20,249 10,177
Income from unconsolidated investments in power
projects.............................................. 36,593 25,240 15,819
Interest income on loans to power projects............... 1,226 2,562 13,048
Other revenue............................................ 5,818 -- --
-------- -------- --------
Total revenue.................................... 847,735 555,948 276,321
-------- -------- --------
Cost of revenue:
Fuel expenses............................................ 268,734 181,593 44,558
Plant operating expenses................................. 118,334 74,486 27,808
Depreciation expense..................................... 82,812 73,988 47,501
Production royalties..................................... 13,767 10,714 10,803
Operating lease expenses................................. 33,594 17,129 14,031
Service contract expenses................................ 40,236 17,417 8,607
-------- -------- --------
Total cost of revenue............................ 557,477 375,327 153,308
-------- -------- --------
Gross profit.......................................... 290,258 180,621 123,013
Project development expenses............................... 10,712 7,165 7,537
General and administrative expenses........................ 53,044 26,780 18,289
-------- -------- --------
Income from operations................................ 226,502 146,676 97,187
Interest expense........................................... 91,162 86,726 61,466
Distributions on trust preferred securities................ 2,565 -- --
Interest income............................................ (24,106) (12,348) (14,285)
Other income............................................... (1,335) (1,075) (3,153)
-------- -------- --------
Income before provision for income taxes.............. 158,216 73,373 53,159
Provision for income taxes................................. 61,973 27,054 18,460
-------- -------- --------
Income before extraordinary charge.................... 96,243 46,319 34,699
Extraordinary charge net of tax benefit of $793, $441 and
$--...................................................... 1,150 641 --
-------- -------- --------
Net income............................................ $ 95,093 $ 45,678 $ 34,699
======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 52,328 40,242 39,892
Income before extraordinary charge....................... $ 1.84 $ 1.15 $ 0.87
Extraordinary charge..................................... $ (0.02) $ (0.01) $ --
Net income............................................... $ 1.82 $ 1.14 $ 0.87
Diluted earnings per common share:
Weighted average shares of common stock outstanding...... 55,661 42,328 42,032
Income before extraordinary charge....................... $ 1.73 $ 1.09 $ 0.83
Extraordinary charge..................................... $ (0.02) $ (0.01) $ --
Net income............................................... $ 1.71 $ 1.08 $ 0.83
The accompanying notes are an integral part of these consolidated financial
statements.
F-28
61
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS)
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK CAPITAL EARNINGS TOTAL
------ ---------- -------- --------
Balance, December 31, 1996....................... $40 $165,392 $ 37,695 $203,127
Issuance of 434,610 shares of common stock,
net......................................... -- 1,022 -- 1,022
Tax benefit from stock options exercised and
other....................................... -- 1,108 -- 1,108
Net income..................................... -- -- 34,699 34,699
--- -------- -------- --------
Balance, December 31, 1997....................... 40 167,522 72,394 239,956
--- -------- -------- --------
Issuance of 201,752 shares of common stock,
net......................................... -- 1,110 -- 1,110
Tax benefit from stock options exercised and
other....................................... -- 222 -- 222
Net income..................................... -- -- 45,678 45,678
--- -------- -------- --------
Balance, December 31, 1998....................... 40 168,854 118,072 286,966
--- -------- -------- --------
Issuance of 22,730,758 shares of common stock,
net......................................... 23 576,573 -- 576,596
Tax benefit from stock options exercised and
other....................................... -- 5,977 -- 5,977
Net income..................................... -- -- 95,093 95,093
--- -------- -------- --------
Balance, December 31, 1999....................... $63 $751,404 $213,165 $964,632
=== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-29
62
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS)
1999 1998 1997
----------- --------- ---------
Cash flows from operating activities:
Net income................................................ $ 95,093 $ 45,678 $ 34,699
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 87,210 74,285 46,819
Deferred income taxes, net.............................. 47,944 13,554 15,082
Income from unconsolidated investments in power
projects.............................................. (36,593) (25,240) (15,819)
Distributions from unconsolidated power projects........ 43,318 27,717 21,042
Loss on sale of assets.................................. 1,058 -- --
Change in operating assets and liabilities, net of
effects of acquisitions:
Accounts receivable................................... (17,258) 10,172 7,249
Notes receivable...................................... (13,919) -- --
Other current assets.................................. (8,555) 24,012 (9,936)
Other assets.......................................... (9,153) (28,968) (13,203)
Accounts payable...................................... 15,867 (4,913) 6,787
Accrued expenses...................................... 59,000 22,397 10,677
Other liabilities..................................... 71 5,885 3,156
----------- --------- ---------
Net cash provided by operating activities.......... 264,083 164,579 106,553
----------- --------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment.............. (929,723) (98,220) (107,094)
Proceeds from sale and leaseback of plant................. 71,236 559 --
Acquisitions, net of cash acquired........................ (540,587) (305,263) (209,639)
Advances to joint ventures................................ (18,111) -- --
Decrease (increase) in notes receivable................... 1,270 18,967 (120,604)
Maturities of collateral securities....................... 1,850 6,030 5,350
Project development costs................................. (77,568) (23,206) (11,938)
Decrease in restricted cash............................... 1,216 1,130 43,675
----------- --------- ---------
Net cash used in investing activities.............. (1,490,417) (400,003) (400,250)
----------- --------- ---------
Cash flows from financing activities:
Borrowings from line of credit............................ -- -- 14,300
Repayment of borrowings from line of credit............... -- -- (14,300)
Borrowings from non-recourse project financing............ 155,760 57,874 131,600
Repayments of non-recourse project financing.............. (123,386) (162,145) (144,529)
Proceeds from notes payable and short-term borrowings..... 163,675 -- --
Repayments of notes payable and short-term borrowings..... (129,721) -- (7,131)
Proceeds from issuance of Senior Notes.................... 600,000 400,000 275,000
Repurchase of Senior Notes................................ -- (8,250) --
Proceeds from Company-obligated mandatorily redeemable
convertible preferred securities of a subsidiary
trust................................................... 276,000 -- --
Proceeds from equity offerings............................ 597,368 -- --
Proceeds from issuance of common stock.................... 2,939 1,110 1,022
Write-off of deferred financing costs..................... 1,943 -- --
Financing costs........................................... (65,405) (5,146) (9,722)
----------- --------- ---------
Net cash provided by financing activities.......... 1,479,173 283,443 246,240
----------- --------- ---------
Net increase (decrease) in cash and cash equivalents........ 252,839 48,019 (47,457)
Cash and cash equivalents, beginning of period.............. 96,532 48,513 95,970
----------- --------- ---------
Cash and cash equivalents, end of period.................... $ 349,371 $ 96,532 $ 48,513
=========== ========= =========
Cash paid during the year for:
Interest.................................................. $ 117,376 $ 71,971 $ 42,746
Income taxes.............................................. $ 16,116 $ 2,167 $ 9,795
The accompanying notes are an integral part of these consolidated financial
statements.
F-30
63
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the generation of electricity in the
United States. In pursuing this single business strategy, the Company is
involved in the development, acquisition, ownership and operation of power
generation facilities and the sale of electricity and its by-product, thermal
energy, primarily in the form of steam. The Company has ownership interests in
and operates gas-fired cogeneration facilities, gas fields, gathering systems
and gas pipelines, geothermal steam fields and geothermal power generation
facilities in northern California, Washington, Texas, Illinois, Oklahoma and
various locations on the East Coast. Each of the generation facilities produces
and markets electricity for sale to utilities and other third party purchasers.
Thermal energy produced by the gas-fired cogeneration facilities is primarily
sold to governmental and industrial users.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The accompanying consolidated financial
statements include accounts of the Company. Wholly-owned and majority-owned
subsidiaries are consolidated. Less-than-majority-owned subsidiaries and
subsidiaries for which control is deemed to be temporary, are accounted for
using the equity method. For equity method investments, the Company's share of
income is calculated according to the Company's equity ownership or according to
the terms of the appropriate partnership agreement (see Note 4). All significant
intercompany accounts and transactions are eliminated in consolidation. Prior to
the Company's acquisition of Unocal's interest in its Geysers geothermal
properties on March 19, 1999, the Company used the proportionate consolidation
method to account for Thermal Power Company's ("TPC's") 25% ownership in jointly
owned geothermal properties.
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates. The most significant estimates with regard to these
financial statements relate to future development costs and useful lives of the
generation facilities (see Property, Plant and Equipment, net).
Cash and Cash Equivalents -- The Company considers all highly liquid
investments with an original maturity of three months or less to be cash
equivalents. The carrying amount of these instruments approximates fair value
because of their short maturity.
Inventories -- Operating supplies are valued at the lower of cost or
market. Cost for large replacement parts estimated to be used within one year is
determined using the specific identification method. For the remaining supplies
and spare parts, cost is determined using the weighted average cost method.
Property, Plant and Equipment, net -- Property, plant and equipment, net
are stated at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities, together with the costs of
production equipment, the related facilities and the operating power plants.
Proceeds from the sale of geothermal properties are applied against capitalized
costs, with no gain or loss recognized.
Geothermal costs, including an estimate of future development costs to be
incurred and the estimated costs to dismantle, are amortized by the units of
production method based on the estimated total productive output over the
estimated useful lives of the related steam fields. Depreciation of the
buildings and roads is
F-31
64
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
computed using the straight-line method over their estimated useful lives. It is
reasonably possible that the estimate of useful lives, total units of production
or total capital costs to be amortized using the units of production method
could differ materially in the near term from the amounts assumed in arriving at
current depreciation expense. These estimates are affected by such factors as
the ability of the Company to continue selling electricity to customers at
estimated prices, changes in prices of alternative sources of energy such as
hydro-generation and gas, and changes in the regulatory environment.
Gas-fired power production facilities include cogeneration plants and
related equipment and are stated at cost. Depreciation is recorded utilizing the
straight-line method over the estimated original useful life of up to 38 years.
The value of the above-market pricing provided in power sales agreements
acquired is recorded in property, plant and equipment, net and is amortized over
the above-market pricing period in the power sales agreement with lives of 3 to
23 years. When assets are disposed of, the cost and related accumulated
depreciation are removed from the accounts, and the resulting gains or losses
are included in results of operations.
As of December 31, 1999 and 1998, the components of property, plant and
equipment, net are as follows (in thousands):
1999 1998
---------- ----------
Geothermal properties............................... $ 366,059 $ 312,139
Oil and gas properties.............................. 214,794 --
Buildings, machinery and equipment.................. 1,215,063 653,865
Power sales agreements.............................. 145,957 145,957
Gas contracts....................................... 122,593 122,561
Other assets........................................ 78,735 18,955
---------- ----------
2,143,201 1,253,477
Less: accumulated depreciation and amortization..... (227,059) (203,984)
---------- ----------
1,916,142 1,049,493
Land................................................ 3,419 1,590
Construction in progress............................ 946,886 43,220
---------- ----------
Property, plant and equipment, net.................. $2,866,447 $1,094,303
========== ==========
Construction in progress is primarily attributable to the projects under
development during 1999 and 1998.
Capitalized Interest -- The Company capitalizes interest on projects during
the development and construction period. For the years ended December 31, 1999,
1998 and 1997 the Company capitalized $47.3 million, $7.0 million and $6.2
million, respectively, of interest in connection with the development and
construction of power plants.
Project Development Costs -- The Company capitalizes project development
costs once it is determined that it is probable that such costs will be realized
through the ultimate construction of a power plant. These costs include
professional services, salaries, permits and other costs directly related to the
development of a new project. Outside services and other third party costs are
capitalized for acquisition projects. Upon the start-up of plant operations or
the completion of an acquisition, these costs are generally transferred to
property, plant and equipment and amortized over the estimated useful life of
the project. Capitalized project costs are charged to expense if the Company
determines that the project is impaired.
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of its debt agreements, lease agreements and by
regulatory agencies. The Company's debt agreements specify
F-32
65
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
restrictions based on debt service payments and drilling costs. Regulatory
agencies require cash to be restricted to ensure that funds will be available to
restore property to its original condition. Restricted cash is invested in
accounts earning market rates; therefore, the carrying value approximates fair
value. Such cash is excluded from cash and cash equivalents for the purposes of
the consolidated statements of cash flows.
Deferred Financing Costs -- Costs incurred in connection with obtaining
financing are deferred and amortized using the effective interest rate method.
The amortization periods range from 4 to 24 years.
Stock Split -- On September 20, 1999, the Board of Directors authorized a
two-for-one stock split of the Company's common stock, in the form of a stock
dividend, effective October 7, 1999, payable to stockholders of record on
September 28, 1999. Par value remains at $0.001 per share as a result of
transferring $27,000 to common stock from additional paid-in capital,
representing the aggregate par value of the shares issued under the stock split.
All references to the number of common shares and the per common share amounts
have been restated to give retroactive effect to the stock split for all periods
presented.
Revenue Recognition -- Revenue from electricity and steam sales is
recognized upon transmission to the customer. Revenues from contracts entered
into or acquired since May 1992 are recognized at the lesser of amounts billable
under the contract or amounts recognizable at an average rate over the term of
the contract. The Company's power sales agreements related to Calpine Geysers
Company ("CGC") were entered into prior to May 1992. Had the Company applied the
methodology described above to the CGC power sales agreements, the revenues
recorded for the years ended December 31, 1999 would have been approximately
$24.2 million higher and the revenues for the years ended December 31, 1998 and
1997 would have been approximately $4.7 million and $20.1 million lower,
respectively.
Calpine Gilroy Cogen, LP ("Gilroy") has a long-term power purchase
agreement ("PPA") with Pacific, Gas and Electric Company ("PG&E") for the sale
of energy through 2018. The terms of the PPA provided for 120 megawatts of firm
capacity and a bonus payment. On December 2, 1999, the California Public
Utilities Commission approved the termination of the PPA between Gilroy and
PG&E. Under terms of the termination, PG&E and Gilroy are each released from any
further performance under the PPA effective November 1, 2002. PG&E is obligated
to pay Gilroy a maximum nominal total of $303.6 million for firm, bonus and as
delivered capacity, which consists of 140 monthly termination payments not to
exceed $20.7 million per year, from February 2002 to September 2014. Gilroy will
record a portion of the present value of the monthly termination payments in
each month following September 1999 through August 2002 as revenue.
The Company performs operations and maintenance services for some of the
projects in which it has an interest. Revenue from investees is recognized as
service contract revenue on these contracts when the services are performed.
The Company also recognizes revenue from power marketing activities through
its wholly owned subsidiary, Calpine Power Services Company ("CPSC"). Revenue
generated from CPSC through sales of purchased power to third parties is also
recorded as service contract revenue.
Revenue from the sale of crude oil is recognized upon the passage of title,
net of royalties. Revenue from natural gas production is recognized using the
sales method, net of royalties.
Oil and Gas Properties -- The Company follows the successful efforts method
of accounting for oil and natural gas operations. Under the successful efforts
method, capitalized costs relating to proved properties are amortized using the
units-of-production method based on estimated proven reserves. The cost of
unsuccessful exploration wells is charged to operations.
Concentrations of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash,
accounts receivable and notes receivable. The
F-33
66
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Company's cash accounts are generally held in FDIC insured banks. The Company's
accounts and notes receivable are concentrated within entities engaged in the
energy industry, mainly within the United States (see Note 13). The Company
generally does not require collateral for accounts receivable.
Derivative Financial Instruments -- The Company engages in activities to
manage risks associated with changes in interest rates. The Company has entered
into swap agreements to reduce exposure to interest rate fluctuations. The
instruments' cash flows mirror those of the underlying exposure. Unrealized
gains and losses relating to the instruments are being deferred over the lives
of the contracts. The premiums paid on the instruments, as measured at
inception, are being amortized over their respective lives as components of
interest expense. Any gains or losses realized upon the early termination of
these instruments are being amortized over the respective lives of the
underlying transaction or recognized immediately if the transaction is
terminated earlier than initially anticipated. Gains and losses on any
instruments not meeting the above criteria would be recognized in income in the
current period. Subsequent gains or losses on the related financial instrument
are recognized in income in each period until the instrument matures, is
terminated or is sold. Cash flows from swap contracts accounted for as hedges
are classified in the same category as the item being hedged.
Power Marketing and Oil and Gas Operations -- The Company, through its
wholly owned subsidiary CPSC, markets power and energy services to utilities,
wholesalers, and end users. CPSC provides these services by entering into
contracts to purchase or supply electricity at specified delivery points and
specified future dates. In some cases, CPSC utilizes financial instruments to
manage its exposure to electricity price fluctuations. On December 31, 1999,
CPSC held swap contracts with several entities in order to hedge electricity
prices. Additionally, the Company or its subsidiaries in some cases uses
financial instruments to manage its exposure to oil and gas price fluctuations.
At December 31, 1999, the Company had positions with a net fair value of
$440,000 to protect the Company against the risks of fluctuating market prices.
The Company actively manages its positions, and it is the Company's policy to
not have any speculative positions. Net gains and losses related to commodity
swap contracts are recognized when realized. The Company's credit risk
associated with power and fuel contracts results from the risk-of-loss on
non-performance by counter parties. The Company reviews and assesses counter
party risk to limit any material impact to its financial position and results of
operations. The Company does not anticipate non-performance by the counter
parties.
New Accounting Pronouncements -- In June 1999, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 137, "Accounting for Derivative Instruments and Hedging
Activities -- Deferral of the Effective Date of FASB Statement No. 133 -- an
Amendment of FASB Statement No. 133". The Statement amends SFAS No. 133 to defer
its effective date to all fiscal quarters of all fiscal years beginning after
June 15, 2000. The Company has not yet completed its analysis on the impact of
adopting SFAS No. 133 on the financial statements and has not determined the
timing of or method of the adoption of SFAS No. 133. However, the Statement
could increase the volatility of the Company's earnings.
Reclassifications -- Certain prior years' amounts in the Consolidated
Financial Statements have been reclassified to conform to the 1999 presentation.
F-34
67
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
3. ACQUISITIONS AND SALE AND LEASEBACK TRANSACTIONS
The following acquisitions, accounted for as purchases, and the additional
investment in Aidlin were consummated during the year ended December 31, 1999:
Unocal Transaction
On March 19, 1999, the Company acquired Unocal Corporation's Geysers
geothermal steam fields in northern California for approximately $102.2 million.
The steam fields fuel the Company's power plants located at the Geysers,
California. See below.
PG&E Transactions
On May 7, 1999, the Company completed the acquisition of 12 Sonoma County
and 2 Lake County power plants, located at the Geysers, California from Pacific
Gas & Electric Company ("PG&E") for approximately $212.8 million. These plants
have a combined capacity of approximately 694 megawatts of electricity. All of
the electricity generated from these facilities is sold into the California
energy market, with the exception of megawatts sold under an agreement entered
into on April 29, 1999 with Commonwealth Energy Corporation as follows: 75
megawatts in 1999, 100 megawatts in 2000 and 125 megawatts in 2001 through June
2002.
Concurrently with the acquisition, the Company entered into a sale and
leaseback financing transaction for these facilities, as well as the Sonoma
power plant acquired from the Sacramento Municipal Utility District in 1998.
Under the terms of the lease, the Company received $18.5 million in net proceeds
and recorded a deferred gain of $15.2 million, which is being amortized as a
reduction of operating lease expense over the term of the lease through 2022
(See Note 15).
Aidlin Transaction
On August 31, 1999, the Company completed the acquisition of an additional
50% interest in the Aidlin Power Plant ("Aidlin") from Edison Mission Energy and
General Electric Capital Corporation for a total purchase price of $7.2 million.
The Company previously owned a 5% interest in Aidlin.
Calistoga and Silverado Transactions
On October 19, 1999, the Company purchased the Calistoga Power Plant, the
Silverado steam fields and related assets from FPL Energy and Caithness
Corporation for $77.9 million. Additionally, on November 5, 1999, the Company
entered into a sale and leaseback financing transaction for the Calistoga plant.
Under the terms of the agreement, the Company received $52.8 million in net
proceeds and did not record a deferred gain or loss. (See Note 15).
Calpine Natural Gas Company Transaction
On October 1, 1999, the Company completed the acquisition of Sheridan
Energy Inc. ("Sheridan"), a natural gas exploration and production company,
through a $38.8 million cash tender offer. The Company purchased the outstanding
shares of Sheridan's common stock for $5.50 per share. In addition, the Company
redeemed $11.9 million of outstanding preferred stock of Sheridan. Sheridan's
oil and gas properties are primarily located in Northern California and the Gulf
Coast region. Previously, the Company had acquired a 20% interest in Sheridan
California Energy, Inc. from Sheridan for $14.9 million. As a result of the two
aforementioned acquisitions, the Company now owns all of the assets of Sheridan
and included the results in its Consolidated Financial Statements at December
31, 1999. The Company subsequently renamed Sheridan as Calpine Natural Gas
Company ("CNGC"). The Company accounted for its investment in Sheridan under
F-35
68
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
the equity method until October 1, 1999. From October 1, 1999 through December
31, 1999, the results of CNGC's operations are consolidated.
Cogeneration Corporation of America Transaction
On December 17, 1999, the Company completed the acquisition of 80% of the
common stock of Cogeneration Corporation of America, Inc. ("CGCA") for
approximately $137.3 million with the remaining 20% being owned by NRG Energy
Inc., a wholly owned subsidiary of Northern States Power. As a result of this
acquisition the Company received an ownership interest in six natural gas-fired
facilities totaling approximately 579 megawatts of capacity and has assumed
operations of five of the plants.
Vintage Transaction
On December 31, 1999, but effective as of November 1, 1999, the Company
acquired proven natural gas reserves and certain leasehold acreage from Vintage
Petroleum, Inc. ("Vintage") of Tulsa, Oklahoma for approximately $71.5 million.
The Company added the remaining 58.8% working interest in the Rio Vista Gas Unit
and certain development acreage to its northern California gas portfolio. This
new production utilizes the Company's Sacramento Basin gas pipeline system. The
Company initially acquired a 40.7% working interest in the Rio Vista Gas Unit in
October 1999 through its Sheridan acquisition.
Pro Forma Effects of Acquisitions
The table below reflects unaudited pro forma combined results of the
Company, Unocal, the power plants acquired from PG&E, Sheridan, Calistoga, CGCA
and Vintage as if the acquisitions had taken place at the beginning of fiscal
year 1999 and 1998 (in thousands, except per share amounts):
1999 1998
---------- --------
Total revenue........................................ $1,057,270 $833,422
Income before extraordinary charge................... 119,817 66,802
Net income........................................... 118,667 66,161
Net income per basic share........................... 2.27 1.64
Net income per diluted share......................... $ 2.13 $ 1.56
In management's opinion, these unaudited pro forma amounts are not
necessarily indicative of what the actual combined results of operations might
have been if the acquisitions had been effective at the beginning of fiscal year
1999 and 1998.
4. UNCONSOLIDATED INVESTMENTS
Investments, which are accounted for under the equity method, are as
follows (in thousands):
DECEMBER 31,
OWNERSHIP --------------------
INTEREST 1999 1998
--------- -------- --------
Tiverton Power Plant....................... 62.8% $ 44,853 $ 40,945
Rumford Power Plant........................ 66.7% 44,316 40,416
Aidlin Power Plant......................... 55% -- 2,635
Lost Pines Power Plant..................... 50% 41,609 --
Kennedy International Airport Power
Plant.................................... 50% 37,880 39,156
Dighton Power Plant........................ 50% 14,875 17,970
Grays Ferry................................ 40% 21,875 --
Stony Brook Power Plant.................... 50% 21,477 20,933
F-36
69
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
DECEMBER 31,
OWNERSHIP --------------------
INTEREST 1999 1998
--------- -------- --------
Auburndale Power Plant..................... 50% 19,565 23,527
Gordonsville Power Plant................... 50% 16,496 16,197
Lockport Power Plant....................... 11.4% 12,406 11,858
Bayonne Power Plant........................ 7.5% 8,490 7,872
PowerRent.................................. 40% 741 --
Agnews Power Plant......................... 20% -- --
Sumas Power Plant.......................... (1) -- --
Other...................................... 251 --
-------- --------
Total Unconsolidated
Investments.................... $284,834 $221,509
======== ========
- ---------------
(1) Refer to Footnote (1) of the table in Note 4 detailing the Company's income
and distributions from investments in unconsolidated power projects.
The combined results of operations and financial position of the Company's
equity method affiliates are summarized below (in thousands):
DECEMBER 31,
--------------------------------------
1999 1998 1997
---------- ---------- ----------
Condensed Statement of Operations:
Revenue.............................. $ 562,401 $ 495,123 $ 271,494
Gross profit......................... 245,314 214,382 73,438
Income from continuing operations.... 214,520 199,601 57,799
Net income........................... 113,837 108,563 30,264
Company's share of net income........ 36,593 25,240 15,819
Condensed Balance Sheet:
Current assets....................... 167,805 134,794 193,953
Non-current assets................... 1,387,130 1,240,172 1,499,501
Total assets......................... 1,554,935 1,374,966 1,693,454
Current liabilities.................. 122,742 110,957 200,613
Non-current liabilities.............. 1,087,329 994,570 1,076,309
Total liabilities.................... 1,210,071 1,105,527 1,276,922
F-37
70
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
The following details the Company's income and distributions from
investments in unconsolidated power projects (in thousands):
INCOME FROM UNCONSOLIDATED
INVESTMENTS IN POWER PROJECTS DISTRIBUTIONS
------------------------------ ---------------------------
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------------------------------
1999 1998 1997 1999 1998 1997
-------- -------- -------- ------- ------- -------
Sumas Power Plant(1)..................... $21,779 $11,699 $ 8,565 $21,779 $11,699 $20,275
Gordonsville Power Plant................. 4,299 3,807 404 4,000 3,125 --
Lockport Power Plant..................... 4,255 3,628 200 3,741 3,297 767
Texas Cogeneration Company(4)............ -- 2,922 6,331 -- -- --
Bayonne Power Plant...................... 3,426 2,446 -- 2,808 2,701 --
Kennedy International Airport Power
Plant.................................. 1,968 1,159 (190) 3,350 4,100 --
Stony Brook Power Plant.................. 857 252 60 370 -- --
Aidlin Power Plant(3).................... 181 625 454 -- -- --
Sheridan................................. 163 -- -- -- -- --
Grays Ferry(2)........................... (3) -- -- -- -- --
Auburndale Power Plant................... (712) (1,377) (245) 3,250 2,475 --
Dighton Power Plant...................... 323 -- -- 3,810 -- --
Other.................................... 57 79 240 210 320 --
------- ------- ------- ------- ------- -------
Total.......................... $36,593 $25,240 $15,819 $43,318 $27,717 $21,042
======= ======= ======= ======= ======= =======
- ---------------
(1) On December 31, 1998, the Partnership agreement governing Sumas Cogeneration
Company, L.P. ("Sumas") was amended changing the distributions schedule for
the Company from the previously amended agreement dated September 30, 1997.
The newly amended agreement adjusts the earnings the Company is entitled to
under that agreement from a variable payment schedule to a fixed payment
schedule. In 1997, the partnership agreement was amended changing the
distribution percentages to the partners. The Company's percentage share of
the project's cash flow was increased from 50% to approximately 70% through
June 30, 2001. Thereafter, the Company will receive 50% of the project's
cash flow until a 24.5% pre-tax rate of return on its original investment is
achieved, at which time the Company's equity interest in the partnership
will be reduced to 0.1%. As a result of the amendment of the partnership
agreement and the receipt of certain distributions during 1997, the
Company's investment in Sumas was reduced to zero. Because the investment
has been reduced to zero and there are no continuing obligations of the
Company related to Sumas, the Company expects that income recorded in future
periods will approximate the amount of cash received from partnership
distributions.
(2) On December 17, 1999, the Company acquired 80% of the common stock CGCA
which has a 50% partnership interest in the Grays Ferry Cogeneration
Partnership ("Grays Ferry") (see Note 3), with the remaining 50% partnership
interest being owned by Trigen Energy Corporation. Grays Ferry has
constructed a 150 MW cogeneration facility located in Philadelphia, which
began commercial operations in January 1998. Grays Ferry has a 25-year
contract to supply all the steam produced by the project to an affiliate of
Trigen through 2022 and two 20-year contracts to supply all of the
electricity produced by the project to PECO Energy Company through 2017.
(3) The Company completed the acquisition of an additional 50% interest in the
Aidlin Power Plant in August, 1999. As such, the Company has consolidated
the operations of the Aidlin Power Plant.
(4) The Company acquired the remaining 50% interest in Texas Cogeneration
Company ("TCC") in 1998 and thereafter has consolidated TCC's financial
results.
The Company provides deferred taxes to the extent that distributions exceed
earnings.
F-38
71
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
5. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
The Company maintains a credit facility of $100.0 million, which is
available through a consortium of commercial lending institutions led by The
Bank of Nova Scotia as agent. A maximum of $50.0 million of the credit facility
may be allocated to letters of credit. At December 31, 1999, the Company had no
borrowings and $28.8 million of letters of credit outstanding under the credit
facility. Borrowings bear interest at The Bank of Nova Scotia's base rate plus
an applicable margin or at LIBOR plus an applicable margin. Interest is paid on
the last day of each interest period for such loans. The credit facility
specifies that the Company maintain certain covenants, with which the Company
was in compliance as of December 31, 1999. Commitment fees related to this
credit facility are charged based on 0.375% of committed unused funds.
CGCA maintains a credit facility of $25.0 million with MeesPierson Capital
Corporation ("MeesPierson"). As of December 31, 1999, all of the available
credit under the facility was outstanding. Interest is variable based on, at the
Company's option, LIBOR plus a margin ranging from 1.50% to 1.875% or the prime
rate plus a margin ranging from 0.75% to 1.125%. At December 31, 1999, the
interest rate was 8.25%. The interest rate margin is dependent upon CGCA's debt
service ratio. Commitment fees of 0.375% accrue on any unused portion of the
facility. Borrowings are secured by the assets, capital stock and cash flows of
the Philadelphia Water Project, which was acquired as part of the acquisition of
CGCA (see Note 3), as well as the distributable cash flows of the Newark, Parlin
and the Grays Ferry Projects, as permitted by primary lenders of each project.
On November 3, 1999, the Company entered into a credit agreement for $1.0
billion through its wholly owned subsidiary Calpine Construction Finance Company
L.P. with a consortium of banks with the lead arranger being The Bank of Nova
Scotia and the lead arranger syndication agent being Credit Suisse First Boston.
The non-recourse credit facility will be utilized to finance the construction of
the Company's diversified portfolio of gas-fired power plants currently under
development. The Company currently intends to refinance this construction
facility in the long-term capital markets prior to its four-year maturity. As of
December 31, 1999, the Company had no borrowings outstanding under the facility.
Borrowings under this facility bear interest, at the Company's option, at the
prime commercial lending rate, the Federal Funds Rate plus 0.50% or LIBOR. The
credit facility specifies that the Company maintain certain covenants, with
which the Company was in compliance as of December 31, 1999. Costs associated
with the credit agreement have been deferred and will be amortized over the life
of the assets financed.
CNGC maintains a borrowing base facility of $24.5 million with Bank One,
Texas, N.A. ("Bank One"). As of December 31, 1999, CNGC had total borrowings
outstanding of $24.3 million with final maturity of December 31, 2001. CNGC may
elect to borrow at Bank One's stated rate, or LIBOR plus 2.5%, or a combination
thereof. At December 31, 1999, the interest rate was 8.6%. The facility is
secured by substantially all of CNGC's oil and gas properties and is repayable
through monthly payments of $350,000. The monthly payments are redetermined
every six months or at Bank One's discretion. The facility requires the
maintenance of certain covenants such as ratios relating to working capital, and
tangible net worth. CNGC was in compliance with all of the facility's covenants
as of December 31, 1999.
In conjunction with the acquisition of certain properties located in
California, Bank One extended a separate borrowing base facility of $74.6
million as of December 31, 1999, to Sheridan California Energy, Inc. ("SCEI"), a
wholly owned subsidiary of CNGC. As of December 31, 1999, there was $73.5
million outstanding under the SCEI facility with a final maturity of December
31, 2001. At December 31, 1999, the interest rate was 8.4%. The SCEI facility is
secured by substantially all of SCEI's oil and gas properties and is repayable
through monthly payments of $775,000. The monthly payments are redetermined
every six months or at Bank One's discretion. The SCEI facility is repayable
only by SCEI and is not an obligation of CNGC. The SCEI facility requires the
maintenance of certain covenants such as ratios relating to working capital, and
tangible net worth. SCEI was in compliance with all of the facility's covenants
as of December 31, 1999.
F-39
72
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Costs incurred regarding the establishment of the CNGC and SCEI facilities
are deferred and amortized over the term of the facilities.
6. PROJECT FINANCING AND INTEREST RATE SWAP AGREEMENTS
The components of project financing as of December 31, 1999 and 1998 are
(in thousands):
INTEREST
RATE(1) DECEMBER 31,
------------ -------------------
PROJECTS 1999 1998 FINAL MATURITY 1999 1998
-------- ---- ---- -------------- -------- --------
Gilroy Power Plant(4)........................... -- 6.8% $ -- $119,640
Morris Power Plant(2)(4)........................ 7.50% -- 2004 85,622 --
Newark & Parlin Power Plants(2)(3)(4)........... 6.51% -- 2011 125,318 --
Pasadena Power Plant(4)......................... 5.58% 5.8% 2005 154,800 --
-------- --------
Total project financing............... 365,740 119,640
Less: current portion........................... 8,603 5,450
-------- --------
Long-term project financing..................... $357,137 $114,190
======== ========
- ---------------
(1) Weighted average rate before giving effect to amortization of financing cost
or interest rate swaps.
(2) Debt assumed as part of the CGCA acquisition on December 17, 1999.
(3) $20.2 million of the Newark & Parlin Plant Debt is guaranteed by CGCA.
(4) The fair value of the project financing approximates its carrying value.
Gilroy Power Plant Debt
In August 1996, the Company entered into an agreement with Banque Nationale
de Paris ("BNP") to finance the acquisition of the Gilroy Power Plant. In April
1999, the Company repaid the entire loan of $120.6 million to ("BNP") with a
portion of the net proceeds from the offering of Senior Notes due 2006. The
Company recorded an extraordinary loss of $1.2 million after taxes as a result
of the repayment for the write-off of unamortized deferred financing cost
associated with the BNP financing.
Morris Power Plant Debt
On December 17, 1999, the Company acquired 80% of the common stock of CGCA
which owns 100% of Morris LLC ("Morris") (see Note 3). In 1997, Morris entered
into a construction and term loan agreement to provide non-recourse project
financing for a major portion of the Morris Project. The agreement provides
$85.6 million of 5 year term loan commitments and $5.4 million in letter of
credit commitments. As of December 31, 1999, $85.6 million was outstanding as a
term loan under the agreement and no amounts were pledged under the letter of
credit. Interest on the term loan is variable based on, at CGCA's option, either
the base rate, as defined in the term loan agreement, or LIBOR plus 0.75%. The
interest rate resets based on CGCA's selection of the borrowing period ranging
from one to six months. The interest rate was 7.5% at December 31, 1999.
Borrowings are secured by CGCA's ownership interest in Morris, its cash flows,
dividends and any other property of Morris.
Newark & Parlin Power Plant Debt
On December 17, 1999, the Company acquired 80% of the common stock of CGCA
which owns 100% of the Newark and Parlin Power Plants ("Newark & Parlin") (see
Note 3). At December 31, 1999 there was $125.3 million outstanding on a fifteen
year non-recourse term loan which is a joint and severable liability of Newark &
Parlin. The term loan is amortized by quarterly principal payments ranging from
1.275% to 1.825%
F-40
73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
through the fourteenth year and 3.075% in the fifteenth year. The term loan is
secured by all Newark & Parlin assets and a pledge of their capital stock. CGCA
has guaranteed repayment of up to $25.0 million of the term loan based on the
principal balance of the loan, and also guaranteed payment by Newark & Parlin of
all income and franchise taxes when due. CGCA's guarantee is reduced
proportionately to the outstanding principal as payments are made on the debt.
The balance of the guarantee was $20.2 million as of December 31, 1999.
The interest rate on the outstanding principal is variable based on, at
CGCA's option, LIBOR plus 1.125% margin or a defined base rate plus 0.375%
margin. For any quarterly period where the debt service coverage is in excess of
1.4:1, both margins are reduced by 0.125%. The interest rate resets based on the
borrowing period selected, generally one to three months. The interest rate was
6.5% at December 31, 1999. Nominal margin increases for both the LIBOR and the
defined base rate will occur in year six and eleven of the Newark & Parlin
Credit Agreement.
The effective interest rate for 1999, after giving effect to the interest
rate swap, was 7.2%. Interest on the loan is payable at least quarterly. At
December 31, 1999, the fair market value of the interest rate swap was
approximately $202,000.
Pasadena Power Plant Debt
On January 4, 1999, the Company entered into a credit agreement with ING
(U.S.) Capital LLC ("ING") to provide up to $265.0 million of non-recourse
project financing for the construction of the Pasadena facility expansion. As of
December 31, 1999, $154.8 million was outstanding as a construction loan under
the agreement. The outstanding loan bears interest at ING's base rate plus an
applicable margin or at LIBOR plus an applicable margin and is payable
quarterly. The construction loan will convert to a term loan once the project
has completed construction. The construction loan will mature on or before July
1, 2000, but is subject to an extension to October 1, 2000 if there are
sufficient construction funds available. The term loan will be available for a
period not to exceed five years from the construction loan maturity date. In
connection with the credit agreement, the Company entered into a $10.0 million
letter of credit facility. At December 31, 1999, there were no letters of credit
outstanding under the facility.
The effective interest rate for 1999, after giving effect to two interest
rate swaps, was 8.2%. Interest on the loan is payable at least quarterly. At
December 31, 1999, the fair market value of these interest rate swaps was
approximately $3.3 million.
Additional Interest Rate Swap Agreements
The Company has entered into two interest rate swap agreements to fix the
interest rates on the Newark & Parlin and CNGC floating rate debt. These hedges
fix an interest rate on $94.3 million at 6.5%. At December 31, 1999, the fair
market value of these hedges was approximately $432,000 and is being deferred
and will be amortized over the lives of the respective project financings.
F-41
74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
7. SENIOR NOTES
Senior Notes payable consist of the following as of December 31, 1999 and
1998 (in thousands):
DECEMBER 31,
---------------------
INTEREST RATES FIRST CALL DATE 1999 1998
-------------- --------------- ---------- --------
Senior Notes due 2004................ 9 1/4% 1999 $ 105,000 $105,000
Senior Notes due 2006................ 10 1/2% 2001 171,750 171,750
Senior Notes due 2006(1)............. 7 5/8% -- 250,000 --
Senior Notes due 2007................ 8 3/4% 2002 275,000 275,000
Senior Notes due 2008(1)............. 7 7/8% -- 400,000 400,000
Senior Notes due 2009(1)............. 7 3/4% -- 350,000 --
---------- --------
Total...................... $1,551,750 $951,750
========== ========
- ---------------
(1) The Senior Notes are not redeemable prior to maturity.
The Company has completed a series of public debt offerings since 1994.
Transaction costs in connection with the debt offerings are capitalized as
deferred financing costs and are being amortized over the ten-year life of the
related offerings. Interest is payable semiannually at specified rates. There
are no sinking fund or mandatory redemptions of principal before the maturity
dates of each offering. The Senior Note indentures limit the Company's ability
to incur additional debt, pay dividends, sell assets and enter into certain
transactions. As of December 31, 1999 the Company is in compliance with all debt
covenants relating to the Senior Notes.
Senior Notes Due 2004
The Senior Notes due 2004 bear interest at 9 1/4% per year, payable
semi-annually on February 1 and August 1 each year and mature on February 1,
2004. The Senior Notes are redeemable, at the option of the Company, at any time
on or after February 1, 1999 at various redemption prices. In addition, the
Company may redeem up to $36.8 million of the Senior Notes from the proceeds of
any public equity offering. The effective interest rate on the $105.0 million,
after amortization of deferred financing costs, was 9.7%. Based on the traded
yield to maturity, the approximate fair market value of the Senior Notes due
2004 was $106.1 million and $108.2 million as of December 31, 1999 and 1998,
respectively.
Senior Notes Due 2006
The Senior Notes due 2006 bear interest at 10 1/2% per year, payable
semi-annually on May 15 and November 15 each year and mature on May 15, 2006.
The Senior Notes are redeemable, at the option of the Company, at any time on or
after May 15, 2001 at various redemption prices. In addition, the Company may
redeem up to $63.0 million of the Senior Notes from the proceeds of any public
equity offering. The effective interest rate on the $171.8 million, after
amortization of deferred financing costs, was 10.8%. Based on the traded yield
to maturity, the approximate fair market value of the Senior Notes due 2006 was
$180.9 million and $188.9 million as of December 31, 1999 and 1998,
respectively.
On March 29, 1999, the Company completed a public offering of $250.0
million of its 7 5/8% Senior Notes Due 2006. The Senior Notes bear interest at
7 5/8% per year, payable semi-annually on April 15 and October 15 and mature on
April 15, 2006. The Senior Notes are not redeemable prior to maturity. The
effective interest rate on the $250.0 million, after amortization of deferred
financing costs, was 8.0%. Based on the traded yield to maturity, the
approximate fair market value of the Senior Notes due 2006 was $238.1 million as
of December 31, 1999. Transaction costs incurred in connection with the Senior
Notes offering were recorded as
F-42
75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
a deferred charge and are amortized over the life of the Senior Notes Due 2006
using the effective interest rate method.
Senior Notes Due 2007
The Senior Notes due 2007 bear interest at 8 3/4% per year, payable
semi-annually on January 15 and July 15 each year and mature on July 15, 2007.
The Senior Notes are redeemable, at the option of the Company, at any time on or
after July 15, 2002 at various redemption prices. In addition, the Company may
redeem up to $96.3 million of the Senior Notes from the proceeds of any public
equity offering. The effective interest rate on the $275.0 million, after
amortization of deferred financing costs, was 9.1%. Based on the traded yield to
maturity, the approximate fair market value of the Senior Notes due 2007 was
$276.0 million and $288.8 million as of December 31, 1999 and 1998,
respectively.
Senior Notes Due 2008
The Senior Notes Due 2008 bear interest at 7 7/8% per year, payable
semi-annually on April 1 and October 1 each year and mature on April 1, 2008.
The Senior Notes are not redeemable prior to maturity. The effective interest
rate on the $400.0 million, after amortization of deferred financing costs, was
8.0%. Based on the traded yield to maturity, the approximate fair market value
of the Senior Notes due 2008 was $384.6 million and $403.0 million as of
December 31, 1999 and 1998, respectively.
Senior Notes Due 2009
On March 29, 1999, the Company completed a public offering of $350.0
million of its 7 3/4% Senior Notes Due 2009 ("Senior Notes Due 2009"). The
Senior Notes Due 2009 bear interest at 7 3/4% per year, payable semi-annually on
April 15 and October 15 and mature on April 15, 2009. The Senior Notes Due 2009
are not redeemable prior to maturity. The effective interest rate on the $350.0
million, after amortization of deferred financing costs, was 8.1%. Based on the
traded yield to maturity, the approximate fair market value of the Senior Notes
due 2009 was $321.0 million as of December 31, 1999. Transaction costs incurred
in connection with the Senior Notes offering were recorded as a deferred charge
and are amortized over the life of the Senior Notes Due 2009 using the effective
interest rate method.
The annual principal maturities of the borrowings under line of credit,
recourse project financings, non-recourse project financings, notes payable and
Senior Notes as of December 31, 1999 are as follows (in thousands):
2000............................................. $ 47,470
2001............................................. 29,423
2002............................................. 30,847
2003............................................. 29,959
2004............................................. 209,875
Thereafter....................................... 1,706,086
----------
Total.................................. $2,053,660
==========
8. TRUST PREFERRED SECURITIES
Concurrently with its public offering in October 1999, the Company, through
its wholly-owned subsidiary, Calpine Capital Trust, a statutory business trust
created under Delaware law, completed an offering of 4,800,000 Remarketable Term
Income Deferrable Equity Securities ("trust preferred securities") ("HIGH
TIDES") at a value of $50.00 per share. The net proceeds from the offering were
approximately
F-43
76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
$233.2 million. The Company sold an additional 720,000 trust preferred
securities at a value of $50.00 per share pursuant to the exercise of the
underwriters' over-allotment option for net proceeds of approximately $35.0
million. The net proceeds from the offering were used by the Company's
subsidiary to invest in convertible subordinated debentures of the Company,
which represent substantially all of the subsidiary's assets. The Company has
guaranteed all of the subsidiary's obligations under the trust preferred
securities. The trust preferred securities are reflected on the balance sheet as
"Company-obligated mandatorily redeemable convertible preferred securities of a
subsidiary trust", while distributions are reflected in the statements of
operations as "Distributions on trust preferred securities". Financing costs
related to the issuance of the trust preferred securities are amortized over 30
years. The trust preferred securities accrue distributions at a rate of 5 3/4%
per annum, have a liquidation value of $50.00 per share, are convertible into
shares of the Company's common stock at the holders option on or prior to the
tender notification date, at a rate of 0.8565 shares of common stock for each
trust preferred security, and may be redeemed at any time on or after November
5, 2002 at a redemption price equal to 101.44% of the principal amount plus any
accrued and unpaid interest declining to 100% of the principal amount on or
after November 5, 2003. Additionally, the Company has the right to defer the
interest payments on the debentures for up to twenty consecutive quarters, which
would also cause a deferral of distributions on the trust preferred securities.
Currently, the Company has no intention of deferring interest payments on the
debentures.
9. COMMON STOCK
On March 26, 1999, the Company completed a public offering of 12,000,000
shares of its common stock at $15.50 per share for net proceeds of approximately
$177.1 million. Additionally, in April 1999, the Company sold an additional
1,800,000 shares of common stock at $15.50 per share pursuant to the exercise of
the underwriters' over-allotment option for net proceeds of approximately $26.7
million.
On October 27, 1999, the Company completed a public offering of 7,200,000
shares of its common stock at $46.31 per share for net proceeds of approximately
$320.3 million. The Company sold an additional 1,080,000 shares of common stock
at $46.31 per share pursuant to the exercise of the underwriters' over-
allotment option for net proceeds of approximately $48.2 million.
10. PROVISION FOR INCOME TAXES
The components of the deferred income taxes, net as of December 31, 1999
and 1998 are as follows (in thousands):
1999 1998
--------- ---------
Expenses deductible in a future period................. $ 7,949 $ 3,721
Net operating loss and credit carryforwards............ 50,358 19,550
Other differences...................................... 1,545 4,340
--------- ---------
Deferred tax assets.................................. 59,852 27,611
--------- ---------
Property differences................................... (340,164) (178,171)
Difference in taxable income and income from
investments recorded on the equity method............ (2,305) (3,796)
Other differences...................................... (8,841) (5,432)
--------- ---------
Deferred tax liabilities............................. (351,310) (187,399)
--------- ---------
Net deferred income taxes......................... $(291,458) $(159,788)
========= =========
The net operating loss and credit carryforwards consist of federal and
state net operating loss carryforwards which expire 2005 through 2014, federal
and state alternative minimum tax credits and federal depletion deduction
carryforwards which can be carried forward indefinitely. The federal and state
net
F-44
77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
operating loss carryforwards available are subject to limitations on annual
usage. It is expected that they will be fully utilized before expiring. At
December 31, 1999, federal and state alternative minimum tax credit
carryforwards were fully utilized. Realization of the deferred tax assets and
federal net operating loss carryforwards is dependent, in part, on generating
sufficient taxable income prior to expiration of the loss carryforwards. The
amount of the deferred tax asset considered realizable, however, could be
reduced in the near term if estimates of future taxable income during the
carryforward period are reduced.
The provision for income taxes for the years ended December 31, 1999, 1998
and 1997 consists of the following (in thousands):
1999 1998 1997
------- ------- -------
Current:
Federal.......................................... $26,564 $ 1,582 $ 1,892
State............................................ 6,728 277 917
Deferred:
Federal.......................................... 23,142 26,830 14,989
State............................................ 4,305 1,772 2,897
Adjustment in state tax rate (net of federal
benefit).................................... -- (4,826) (2,113)
Revision in prior years' tax estimates........ 1,234 1,419 (122)
------- ------- -------
Total provision.......................... $61,973 $27,054 $18,460
======= ======= =======
The Company's effective rate for income taxes for the years ended December
31, 1999, 1998 and 1997 differs from the United States statutory rate, as
reflected in the following reconciliation:
1999 1998 1997
---- ---- ----
United States statutory tax rate..................... 35.0% 35.0% 35.0%
State income tax, net of federal benefit............. 3.6 3.8 5.0
Depletion allowance.................................. -- (1.5) (2.1)
Decrease in California deferred tax due to Company's
expansion into other states, net of federal
benefit............................................ -- -- (4.1)
Other, net........................................... 0.6 (0.4) 0.9
---- ---- ----
Effective income tax rate.......................... 39.2% 36.9% 34.7%
==== ==== ====
11. EMPLOYEE BENEFIT PLANS
Retirement Savings Plan
The Company has a defined contribution savings plan under Section 401(a)
and 501(a) of the Internal Revenue Code. The plan provides for tax deferred
salary deductions and after-tax employee contributions. Employees automatically
become participants on the first quarterly entry date after completion of three
months of service. Contributions include employee salary deferral contributions
and a 3% employer profit-sharing contribution. Employer profit-sharing
contributions in 1999, 1998 and 1997 totaled $1.3 million, $829,000 and
$588,000, respectively.
1996 Employee Stock Purchase Plan
The Company adopted the 1996 Employee Stock Purchase Plan ("ESPP") in July
1996. Eligible employees may purchase up to 550,000 shares of common stock at
semi-annual intervals through periodic payroll deductions. Purchases are limited
to 15 percent of an employee's eligible compensation, up to a maximum of $25,000
per year. Shares are purchased on January 31 and July 31 of each year until
termination
F-45
78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
of the plan on February 1, 2000. Under the ESPP, 205,522 shares were issued at a
weighted average fair value of $7.69 per share in 1999. In January 2000,
employees participating in the ESPP purchased an additional 101,712 shares at a
weighted average fair value of $10.65 per share. The purchase price is 85% of
the lower of (i) the fair market value of the common stock on the participant's
entry date into the offering period, or (ii) the fair market value on the
semi-annual purchase date.
1996 Stock Incentive Plan
The Company adopted the 1996 Stock Incentive Plan ("SIP") in September
1996. The SIP succeeded the Company's previously adopted stock option program.
The Company accounts for the SIP under Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" under which no compensation cost
has been recognized. Had compensation cost for the SIP been determined
consistent with the methodology of SFAS No. 123, "Accounting for Stock-Based
Compensation", the Company's net income and earnings per share would have been
reduced to the following pro forma amounts (in thousands, except per share
amounts):
1999 1998 1997
------- ------- -------
Net income.............................. As reported $95,093 $45,678 $34,699
Pro Forma 87,417 43,965 33,272
Earnings per share data:
Basic earnings per share................ As reported $ 1.82 $ 1.14 $ 0.87
Pro Forma 1.67 1.09 0.83
Diluted earnings per share.............. As reported 1.71 1.08 0.83
Pro Forma 1.57 1.04 0.79
The fair value of options granted in 1999, 1998 and 1997 was $17.88, $3.61
and $5.14 on the date of grant using the Black-Scholes option pricing model with
the following weighted-average assumptions: expected dividend yields of 0%,
expected volatility of 69% for 1999, 35% for 1998 and 44% for 1997, risk-free
interest rates of 5.74% for 1999, 5.25% for 1998, 5.8%, for 1997, respectively,
and expected lives of 7 years for 1999, 1998 and 1997.
The Company may grant options for up to 9,285,028 shares under the SIP. As
of December 31, 1999, the Company had granted options to purchase 8,252,780
shares of common stock, net of cancellations. Over the life of the SIP, options
exercised have equaled 749,128, leaving 7,503,652 granted and not yet exercised.
Under the SIP, the option exercise price equals the stock's fair market value on
date of grant. The SIP options generally vest after four years and expire after
10 years. Changes in options outstanding, granted, exercisable
F-46
79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
and cancelled by the Company during the years 1999, 1998 and 1997, whether under
the option or purchase plan were as follows:
AVAILABLE FOR WEIGHTED
OPTION OR NUMBER OF AVERAGE
AWARD SHARES EXERCISE PRICE
------------- --------- --------------
Beginning as of January 1, 1997................ 3,393,128 4,680,588 $ 1.85
Granted................................... (788,434) 788,434 9.15
Exercised................................. -- (326,312) 0.66
Cancelled................................. 103,104 (103,104) 4.28
---------- ---------
Outstanding December 31, 1997.................. 2,707,798 5,039,606 3.01
Additional shares reserved................... 798,082 -- --
Granted................................... (841,450) 841,450 8.52
Exercised................................. -- (67,580) 1.48
Cancelled................................. 44,596 (44,596) 7.82
---------- ---------
Outstanding December 31, 1998.................. 2,709,026 5,768,880 3.80
Additional shares reserved................... 403,230 -- --
Granted................................... (2,086,608) 2,086,608 24.52
Exercised................................. -- (345,236) 2.89
Cancelled................................. 6,600 (6,600) 15.20
---------- ---------
Outstanding December 31, 1999.................. 1,032,248 7,503,652 $ 9.59
========== =========
Options exercisable:
December 31, 1997............................ 3,270,938 $ 1.61
December 31, 1998............................ 3,853,610 2.19
December 31, 1999............................ 4,352,513 $ 2.95
The following tables summarizes information concerning outstanding and
exercisable options at December 31, 1999:
OUTSTANDING OPTIONS
------------------------------------ OPTIONS EXERCISABLE
WEIGHTED --------------------
AVERAGE WEIGHTED WEIGHTED
REMAINING AVERAGE AVERAGE
NUMBER OF CONTRACTUAL EXERCISE NUMBER OF EXERCISE
RANGE OF EXERCISE PRICES SHARES LIFE IN YEARS PRICE SHARES PRICE
------------------------ --------- ------------- -------- --------- --------
$ 0.25 - $ 0.25..................... 1,604,940 3.00 $ 0.25 1,604,940 $ 0.25
$ 0.93 - $ 2.29..................... 629,846 4.48 2.04 629,846 2.04
$ 2.45 - $ 2.45..................... 754,710 5.33 2.45 754,710 2.45
$ 2.58 - $ 4.29..................... 919,034 6.31 4.25 684,005 4.24
$ 4.43 - $ 8.60..................... 762,798 8.18 8.43 219,048 8.02
$ 8.78 - $13.28..................... 865,364 7.49 9.60 444,964 9.47
$15.01 - $15.44..................... 1,059,200 9.12 15.44 -- --
$16.97 - $39.81..................... 883,400 9.56 36.48 15,000 27.72
$40.00 - $54.63..................... 24,120 9.86 49.19 -- --
$57.00 - $57.00..................... 240 9.97 57.00 -- --
--------- ---------
Total..................... 7,503,652 6.47 $ 9.59 4,352,513 $ 2.95
========= =========
F-47
80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
12. STOCKHOLDERS' EQUITY
Preferred Stock and Preferred Share Purchase Rights
On June 5, 1997, the Board of Directors adopted a Stockholders Rights Plan
("Rights Plan") to strengthen the Board of Directors ability to protect the
Company's stockholders. The Rights Plan is designed to protect against abusive
or coercive takeover tactics that are not in the best interests of the Company
and its stockholders. To implement the Rights Plan, the Board of Directors
declared a dividend of one preferred share purchase right (a "Right") for each
outstanding share of common stock, par value $0.001 per share, held on record as
of June 18, 1997, and directed the issuance of one Right with respect to each
share of Common Stock that shall become outstanding between the Record Date and
the Distribution Date. On December 31, 1999, there were 63,053,920 Rights
outstanding. Each Right initially represents a contingent right to purchase,
under certain circumstances, one one-thousandth of a share (a "Unit") of Series
A Junior Participating Preferred Stock, par value $0.001 per share (the
"Preferred Stock"), of the Company at a price of $80.00 per Unit, subject to
adjustment. The Rights become exercisable and trade independently from the
Company's common stock upon the public announcement of the acquisition by a
person or group of 15% or more of the Company's common stock, or ten days after
commencement of a tender or exchange offer that would result in the acquisition
of 15% or more of the Company's common stock. Each Unit of Preferred Stock
purchased upon exercise of the Rights will be entitled to a dividend equal to
any dividend declared per share of common stock and will have one vote, voting
together with the common stock. In the event of liquidation, each share of
Preferred Stock will be entitled to any payment made per share of common stock.
If the Company is acquired in a merger or other business combination
transaction after a person or group has acquired 15% or more of the Company's
common stock, each Right will entitle its holder to purchase at the Right's
exercise price a number of the acquiring company's common shares having a market
value of twice such exercise price. In addition, if a person or group acquires
15% or more of the Company's common stock, each Right will entitle its holder
(other than the acquiring person or group) to purchase, at the Right's exercise
price, a number of fractional shares of the Company's Preferred Stock or shares
of common stock having a market value of twice such exercise price.
The Rights expire June 18, 2007, unless redeemed earlier by the Company's
Board of Directors. The Board of Directors can redeem the Rights at a price of
$0.01 per Right at any time before the Rights become exercisable, and thereafter
only in limited circumstances.
13. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- Pacific Gas & Electric Company ("PG&E") and Texas Utilities Electric
Company ("TUEC").
Revenues earned from these sources for the years ended December 31, 1999,
1998 and 1997 were as follows (in thousands):
1999 1998 1997
-------- -------- --------
REVENUES:
PG&E....................................... $215,264 $222,593 $221,457
TUEC....................................... 144,016 128,724 --
F-48
81
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Accounts receivable at December 31, 1999, and 1998 were as follows (in
thousands):
1999 1998
------- -------
ACCOUNTS RECEIVABLE:
PG&E..................................................... $33,251 $25,186
TUEC..................................................... 9,918 15,052
14. EARNINGS PER SHARE
Basic earnings per common share were computed by dividing net income by the
weighted average number of common shares outstanding for the period. The
dilutive effect of the potential exercise of outstanding options to purchase
shares of common stock is calculated using the treasury stock method. The
reconciliation of basic earnings per common share to diluted earnings per share
is shown in the following table (dollars in thousands except share data). All
share data has been adjusted to reflect the two-for-one stock split effective
October 7, 1999.
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ------------------------
NET NET NET
INCOME SHARES EPS INCOME SHARES EPS INCOME SHARES EPS
------- ------ ------ ------- ------ ------ ------- ------ -----
BASIC EARNINGS PER COMMON SHARE:
Income before extraordinary
Charge...................... $96,243 52,328 $ 1.84 $46,319 40,242 $ 1.15 $34,699 39,892 $0.87
Extraordinary charge net of
tax benefit of $793 and $441
for 1999 and 1998,
respectively................ 1,150 (0.02) 641 (0.01) -- --
------- ------ ------ ------- ------ ------ ------- ------ -----
Net income.................... $95,093 52,328 $ 1.82 $45,678 40,242 $ 1.14 $34,699 39,892 $0.87
======= ====== ====== ======= ====== ====== ======= ====== =====
Common shares issuable upon
Exercise of stock options
using treasury stock
method...................... 3,333 2,086 2,140
------ ------ ------
DILUTED EARNINGS PER
COMMONSHARE:
Income before extraordinary
Charge...................... $96,243 55,661 $ 1.73 $46,319 42,328 $ 1.09 $34,699 42,032 $0.83
Extraordinary charge net of
tax benefit of $793 and $441
for 1999 and 1998,
respectively................ 1,150 (0.02) 641 (0.01) -- --
------- ------ ------ ------- ------ ------ ------- ------ -----
Net income.................... $95,093 55,661 $ 1.71 $45,678 42,328 $ 1.08 $34,699 42,032 $0.83
======= ====== ====== ======= ====== ====== ======= ====== =====
The Company recognized an extraordinary charge of $1.2 million or $0.02 per
share (net of tax benefit of $793,000) in April of 1999, representing the
write-off of deferred financing costs related to non-recourse project financing
for the Gilroy Power Plant. The financing agreement was terminated and the
outstanding balance as of April 1999 of $120.6 million was repaid.
In 1998, the Company recognized a $641,000 extraordinary charge (net of tax
benefit of $441,000), for the repurchase of $8.3 million of the 10 1/2% Senior
Notes Due 2006. The notes were redeemed at a premium plus accrued interest to
the date of repurchase.
Unexercised employee stock options to purchase 240 shares of the Company's
common stock during the year ended December 31, 1999 were not included in the
computation of diluted shares outstanding because such inclusion would be
anti-dilutive. There were no ant-dilutive unexercised employee stock options
during the year ended December 31, 1998. Unexercised employee stock options to
purchase 385,000 shares of the Company's common stock during the year ended
December 31, 1997 were not included in the computation of diluted shares
outstanding because such inclusion would be anti-dilutive.
F-49
82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
15. COMMITMENTS AND CONTINGENCIES
Production Royalties and Leases -- The Company is committed under numerous
geothermal leases and right-of-way, easement and surface agreements. The
geothermal leases generally provide for royalties based on production revenue
with reductions for property taxes paid. The right-of-way, easement and surface
agreements are based on flat rates and are not material. Under the terms of
certain geothermal leases prior to May, 1999 when we consolidated the steam
field and power plant operations at The Geysers, royalties accrued at rates
ranging from 3% to 14% of steam and effluent revenue. Following the
consolidation of operations, the royalties began to accrue as a percentage of
electrical revenues. Certain properties also have net profits and overriding
royalty interests ranging from approximately 1% to 28%, which are in addition to
the land royalties. Most lease agreements contain clauses providing for minimum
lease payments to lessors if production temporarily ceases or if production
falls below a specified level.
Expenses under these agreements for the years ended December 31, 1999, 1998
and 1997 are (in thousands):
1999 1998 1997
------- ------- -------
Production royalties.......................... $13,767 $10,714 $10,803
Natural Gas Purchases -- The Company enters into short-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects.
Office and Equipment Leases -- The Company leases its corporate office and
regional offices in Boston, Massachusetts, Houston, Texas, Pleasanton,
California, San Jose, California, Sacramento, California, and Minneapolis,
Minnesota under noncancellable operating leases expiring through 2006. Future
minimum lease payments under these leases are as follows (in thousands):
2000............................................... $ 4,781
2001............................................... 5,121
2002............................................... 4,936
2003............................................... 4,712
2004............................................... 3,573
Thereafter......................................... 2,429
-------
Total.................................... $25,552
=======
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 1999,
1998 and 1997 rent expense for noncancellable operating leases amounted to $3.1
million, $1.2 million and $1.2 million, respectively.
Cogeneration Facilities Operating Leases -- The Company entered into
long-term operating leases in June 1995, April 1996, August 1998 and May 1999
for its Watsonville, King City, and Greenleaf cogeneration facilities and for
The Geysers Power Plants. Future minimum lease payments under these leases are
as follows (in thousands):
2000 2001 2002 2003 2004 THEREAFTER TOTAL
------- ------- ------- ------- ------- ---------- --------
Watsonville................... $ 2,905 $ 2,905 $ 2,905 $ 2,905 $ 2,905 $ 15,682 $ 30,207
King City..................... 20,254 21,015 21,848 22,781 13,975 130,011 229,884
Greenleaf..................... 8,991 9,070 8,990 8,994 8,858 71,651 116,554
Geysers (see Note 3).......... 45,009 43,676 47,992 37,152 37,541 246,378 457,748
------- ------- ------- ------- ------- -------- --------
Total.................... $77,159 $76,666 $81,735 $71,832 $63,279 $463,722 $834,393
======= ======= ======= ======= ======= ======== ========
F-50
83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
In 1999, 1998 and 1997, rent expense for cogeneration facilities operating
leases amounted to $33.6 million, $15.7 million and $16.6 million, respectively.
The Watsonville operating lease provides for additional contingent rents payable
during the period from July through December. Contingent rent expense for 1999,
1998 and 1997 amounted to $393,000, $1.5 million and $864,000, respectively.
The King City operating lease commitment is supported by $90.7 million of
collateral securities consisting of investment grade and U.S. Treasury
securities that mature serially in amounts equal to a portion of the semi-annual
lease payment.
Capital expenditures -- At December 31, 1999, the Company is under contract
or letter of intent with Siemens Westinghouse Power Corporation for 63 turbines
for a total purchase price of $2.3 billion related to the Company's power
development projects. Approximate payments related to these turbines are $496.4
million, $655.4 million, $398.9 million, $227.0 million, $84.5 million and $10.6
million in 2000, 2001, 2002, 2003, 2004 and thereafter, respectively.
At December 31, 1999, the Company is also under contract with General
Electric Company for 6 turbines for a total purchase price of $374.5 million
related to the Company's power development projects. Approximate payments
related to these turbines are $118.8 million, $53.9 million, $18.0 million and
$4.5 million in 2000, 2001, 2002 and 2003, respectively.
Litigation
Legal Matters -- On September 30, 1997, a lawsuit was filed by Indeck North
American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois
against Norweb plc. and certain other parties, including the Company. Some of
Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50%
interest in Gordonsville Energy L.P. from Northern Hydro Limited and Calpine
Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant
Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck
claimed that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the
Company tortuously interfered with Indeck's contractual rights to purchase such
interests and conspired with other parties to do so. Indeck is seeking $25.0
million in compensatory damages, $25.0 million in punitive damages, and the
recovery of attorneys' fees and costs. In April 1999, the court dismissed the
claims against Calpine Auburndale and Calpine Gordonsville with prejudice.
Indeck appealed the court's decision. The outcome of the appeal is not expected
until late 2000. The Company is unable to predict the outcome of these
proceedings but it does not expect that the outcome of these proceedings will
have a material adverse effect on its financial position or results of
operations.
An action was filed against Lockport Energy Associates, L.P. and the New
York Public Service Commission ("NYPSC") in August 1997 by NYSEG in the Federal
District Court for the Northern District of New York. NYSEG has requested the
Court to direct NYPSC and the FERC to modify contract rates to be paid to the
Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that
the FERC PURPA and the Federal Power Act by failing to reform the NYSEG contract
that was previously approved by the NYPSC. The Company is unable to predict the
outcome of these proceedings but it does not expect that the outcome of these
proceedings will have a material adverse effect on the Company's financial
position or results of operation. In any event, the Company retains the right to
require The Brooklyn Union Gas Company to purchase its interest in the Lockport
Power Plant for $18.9 million, less equity distributions received by us, at any
time before December 19, 2001.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations.
F-51
84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
16. SUBSEQUENT EVENTS
In January 2000, the Company completed an offering under Rule 144A of the
Securities Act of 6,000,000 5 1/2% HIGH TIDES issued by a subsidiary trust at
$50.00 each, raising $292.4 million of aggregate net proceeds. In February 2000,
the Company sold an additional 1,200,000 5 1/2% HIGH TIDES pursuant to the
exercise of the underwriters' over-allotment option for net proceeds of
approximately $58.6 million.
In January and February 2000, the Company acquired various assets for
approximately $60.5 million, including a 50% interest in the Aries Power Plant
and 100% of the stock of Western Gas Resources California.
17. QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
The Company's quarterly operating results have fluctuated in the past and
may continue to do so in the future as a result of a number of factors,
including, but not limited to, the timing and size of acquisitions, the
completion of development projects, the timing and amount of curtailment of
operations under the terms of certain power sales agreements, and variations in
levels of production. Furthermore, the majority of capacity payments under
certain of the Company's power sales agreements are received during the months
of May through October.
The Company's common stock has been traded on the New York stock exchange
since September 19, 1996. There were 110 common stockholders of record at
December 31, 1999. No dividends were paid for the
F-52
85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
years ended December 31, 1999 and 1998. All share data has been adjusted to
reflect the two-for-one stock split effective October 7, 1999.
QUARTER ENDED
---------------------------------------------------
DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31,
------------ ------------- -------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1999
Total revenue..................................... $247,497 $263,648 $190,677 $145,913
Gross profit...................................... 88,023 103,815 62,014 36,406
Income from operations............................ 66,189 87,105 48,789 24,419
Income before extraordinary charge................ 30,766 42,917 18,710 3,850
Extraordinary charge.............................. -- -- 1,150 --
Net income........................................ 30,766 42,917 17,560 3,850
Basic earnings per common share:
Income before extraordinary charge.............. $ 0.51 $ 0.79 $ 0.35 $ 0.09
Extraordinary charge............................ -- -- (0.02) --
Net income...................................... 0.51 0.79 0.33 0.09
Diluted earnings per common share:
Income before extraordinary charge.............. $ 0.48 $ 0.74 $ 0.33 $ 0.09
Extraordinary charge............................ -- -- (0.02) --
Net income...................................... 0.48 0.74 0.31 0.09
Common stock price per share:
High............................................ $ 64.94 $ 47.88 $ 29.50 $ 18.69
Low............................................. 42.69 27.41 17.56 12.63
1998
Total revenue..................................... $173,033 $186,173 $141,597 $ 55,145
Gross profit...................................... 50,935 69,069 44,841 15,776
Income from operations............................ 40,262 59,959 37,596 8,859
Income before extraordinary charge................ 14,033 23,415 11,928 (3,057)
Extraordinary charge.............................. -- 339 302 --
Net income (loss)................................. 14,033 23,076 11,626 (3,057)
Basic earnings per common share:
Income before extraordinary charge.............. $ 0.35 $ .58 $ 0.30 $ (0.08)
Extraordinary charge............................ -- (0.01) (0.01) --
Net income...................................... 0.35 .57 0.29 (0.08)
Diluted earnings per common share:
Income before extraordinary charge.............. $ 0.33 $ .55 $ 0.29 $ (0.07)
Extraordinary charge............................ -- (0.01) (0.01) --
Net income (loss)............................... 0.33 .54 0.28 (0.07)
Common stock price per share:
High............................................ $ 13.81 $ 10.75 $ 10.63 $ 9.25
Low............................................. 8.59 8.56 8.63 6.38
F-53
86
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(b)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(b)
4.1 -- Indenture dated as of February 17, 1994 between the Company
and Shawmut Bank of Connecticut, National Association, as
Trustee, including form of Notes.(a)
4.2 -- Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(c)
4.3 -- Indenture dated as of July 8, 1997 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(e)
4.4 -- Indenture dated as of March 31, 1998 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(g)
4.5 -- Indenture dated as of March 26, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.6 -- Indenture dated as of April 21, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.7 -- 1999 HIGH TIDES.
4.7.1 -- Certificate of Trust of Calpine Capital Trust, a Delaware
statutory trust, filed October 4, 1999.(i)
4.7.2 -- Corrected Certificate of Certificate of Trust of Calpine
Capital Trust, a Delaware statutory trust, dated September
29, 1999.(i)
4.7.3 -- Declaration of Trust of Calpine Capital Trust, dated as of
October 4, 1999, among Calpine Corporation, as Depositor,
The Bank of New York (Delaware), as Delaware Trustee, The
Bank of New York, as Property Trustee, and the
Administrative Trustees named therein.(i)
4.7.4 -- Indenture, dated as of November 2, 1999, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(i)
4.7.5 -- Remarketing Agreement, dated November 2, 1999, among Calpine
Corporation, Calpine Capital Trust, The Bank of New York, as
Tender Agent, and Credit Suisse First Boston Corporation, as
Remarketing Agent.(i)
4.7.6 -- Amended and Restated Declaration of Trust of Calpine Capital
Trust, dated as of November 2, 1999, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, and The Bank of
New York, as Property Trustee, and the Administrative
Trustees named therein, including form of Preferred Security
and form of Common Security.(i)
4.7.7 -- Preferred Securities Guarantee Agreement, dated as of
November 2, 1999, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(i)
4.8 -- 2000 HIGH TIDES.
4.8.1 Certificate of Trust of Calpine Capital Trust II, a Delaware
statutory trust, filed January 25, 2000.(*)
4.8.2 Declaration of Trust of Calpine Capital Trust II, dated as
of January 24, 2000, among Calpine Corporation, as Depositor
and Debenture Issuer, The Bank of New York (Delaware), as
Delaware Trustee, The Bank of New York, as Property Trustee,
and the Administrative Trustees named therein.(*)
4.8.3 Indenture, dated as of January 31, 2000, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(*)
87
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
4.8.4 Remarketing Agreement, dated as of January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, The Bank of
New York, as Tender Agent, and Credit Suisse First Boston
Corporation, as Remarketing Agent.(*)
4.8.5 Registration Rights Agreement, dated January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, Credit Suisse
First Boston Corporation and ING Barings LLC.(*)
4.8.6 Amended and Restated Declaration of Trust of Calpine Capital
Trust II, dated as of January 31, 2000, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, The Bank of New
York, as Property Trustee, and the Administrative Trustees
named therein, including form of Preferred Security and form
of Common Security.(*)
4.8.7 -- Preferred Securities Guarantee Agreement, dated as of
January 31, 2000, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(*)
10.1 -- Purchase Agreements.
10.1.1 -- Purchase and Sale Agreement dated March 27, 1997 for the
purchase and sale of shares of Enron/Dominion Cogen Corp.
Common Stock among Enron Power Corporation and Calpine
Corporation.(f)
10.1.2 -- Stock Purchase and Redemption Agreement dated March 31,
1998, among Dominion Cogen, Inc. Dominion Energy, Inc. and
Calpine Finance.(f)
10.2 Financing Agreements.
10.2.1 Calpine Construction Finance Company Financing
Agreement.(j)(*)
10.3 -- Other Agreements.
10.3.1 -- Calpine Corporation Stock Option Program and forms of
agreements thereunder.(a)
10.3.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements thereunder.(b)
10.3.3 -- Calpine Corporation Employee Stock Purchase Plan and forms
of agreements thereunder.(b)
10.3.4 -- Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(*)
10.3.5 -- Executive Vice President Employment Agreement between
Calpine Corporation and Ms. Ann B. Curtis.(k)
10.3.6 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A. Walter.(k)
10.3.7 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D. Kelly.(k)
10.3.8 -- Executive Vice President Employment Agreement between
Calpine Corporation and Mr. Thomas R. Mason.(k)
10.4 -- Form of Indemnification Agreement for directors and
officers.(b)
21 -- Subsidiaries of the Company.(*)
23 -- Consents from Arthur Andersen for Form S-8.(*)
27 -- Financial Data Schedule.(*)
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
88
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, and filed on March 27, 1996.
(e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(f) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
(g) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-61047).
(h) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-72583).
(i) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-87427).
(j) Approximately 200 pages of this exhibit have been omitted pursuant to a
request for confidential treatment. The omitted language has been filed
separately with the Securities and Exchange Commission.
(k) Incorporated by reference to Registrant's Form 10-Q/A dated September 30,
1999, and filed on November 17, 1999.
(*) Filed herewith.